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204-017
1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" B 108' 9-5/8" L-80 2352' 7" L-80 5276' 3-1/2" L-80 5670' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate 3340' 10065' SIZE 26# 10943' 2374' 5202' 62.5# 40# 108' Sr Res EngSr Pet GeoSr Pet Eng Oil-Bbl: Water-Bbl: 51 bbl 15.8 ppg Cement 2662-3345' 39 bbl 15.8 ppg PTA Cement w 5 lbs/bbl Bridgemaker II LCM Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing 7889-9803' 2505-2662' SUSPENDED 10216-10236' MD and 5339-5348' TVD (cemented) 10250-10290' MD and 5354-5371' TVD (cemented) 10510-10570' MD and 5467-5493' TVD (cemented) 10644-10664' MD and 5527-5537' TVD (cemented) Gas-Oil Ratio:Choke Size: 15 bbl 15.8 ppg Cement Per 20 AAC 25.283 (i)(2) attach electronic information DEPTH SET (MD) 9893' MD/ 5202' TVD PACKER SET (MD/TVD) 42" 12.25" 110 sx LiteCrete 28'396 sx AS Lite, 297 sx LiteCrete 9.3# 29' 9893' 3287'28' 29' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): WT. PER FT.GRADE 2/5/2004 CEMENTING RECORD 5861918 1399' MD/ 1355' TVD SETTING DEPTH TVD 5861297 TOP HOLE SIZE AMOUNT PULLED 442058 441641 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A 9. Ref Elevations: KB: 28' BOTTOM Kuparuk River Field/Meltwater Oil Pool- Suspended ADL0373112, ADL0389058 None 50-103-20483-00-00 KRU 2P-419888' FNL, 2148' FWL, Sec. 17, T8N, R7E, UM 1962' FSL, 287' FEL, Sec. 19, T8N, R7E, UM L32092/ 32409 1/21/2004 10945' MD/ 5671' TVD 2505' MD / 1999' TVD P.O. Box 100360, Anchorage, AK 99510-0360 444108 5868988 2587' FSL, 127' FWL, Sec. 20, T8N, R7E, UM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 11/8/2025 204-017/ 325-300/ 325-626 ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 51.7 bbl Class G6.125" TUBING RECORD 223 sx Class G, 209 sx Class G8.5" 9946'4-1/2" CASING Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 7:51 am, Dec 09, 2025 Suspended 11/8/2025 JSB RBDMS JSB 122925 xG Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1399' 1355' Top of Productive Interval 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Erica Livingston Digital Signature with Date:Contact Email: Erica.J.Livingston@conocophillips.com Contact Phone:(907) 265-1588 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Interventions and Integrity Supervisor/Engineer Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Authorized Name and N/A - Suspended INSTRUCTIONS Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Authorized Title: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A - Suspended Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Erica Livingston Digitally signed by Erica Livingston Date: 2025.12.08 15:26:20 -09'00' Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB (Tagged TOC) 7,889.0 2P-419 3/30/2024 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Update post RWO 2P-419 3/7/2025 rogerba Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 3,340.0 10,065.3 5,276.4 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth … 2,447.8 Set Depth … 1,973.9 String Max No… 4 1/2 Tubing Description Tubing – Kill String Wt (lb/ft) 12.60 Grade L-80 Top Connection NSCT ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 2,416.7 1,960.4 64.22 Shoe - Mule 4.500 4 1/2" 12.6 ppf, L-80 NSCT Tubing Mule Shoe 3.958 Top (ftKB) 3,685.0 Set Depth … 9,946.1 Set Depth … 5,225.4 String Max No… 4 1/2 Tubing Description Tubing – Completion Lower Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.4 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.1 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.5 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 3,340.0 2,374.2 64.75 CUT 2/19/2025 6.800 3,345.0 2,376.3 64.75 CIBP CIBP set 2/18/2025 0.000 3,685.0 2,528.7 61.77 CUT WELLTEC MECHANICAL TBG CUT AT 3685' RKB 3/31/2024 3.958 9,800.0 5,162.8 65.09 TUBING PUNCH 3' TUBING PUNCH, 2", 7 GRAM, 6 SPF, 18 0.61" HOLES 3/23/2024 3.958 10,199.3 5,332.3 65.08 CIBP Set 2.62" CIBP (mid-element @ 10200' RKB) OAL=1.37' 3/9/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 35.0 3,287.0 35.0 2,351.6 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 105Drag up (lbs): 125Time started reciprocating: 21:30Time stopped reciprocating: 02:37Annular flow after cement job (Y/N): NCirculating BHT (F): 65Static BHT (F): 51Pressure before cementing (psi): 375Hours circulated between stages: 3Bbls cmt to surf: 136.6Method used to measure density: DensometerMethod used for mixing cement in this stage: TubReturns (pct): FULLTime cementing mixing started: 01:30 1/24/2004 2P-419, 12/3/2025 12:13:30 PM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 Pre-Flush; 10,065.0 ftKB IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 CIBP; 10,199.3 PRODUCTION; 3,340.0- 10,065.3 TUBING PUNCH; 9,800.0 GAS LIFT; 9,776.5 Cement Plug; 7,889.0 ftKB Cement Plug; 7,889.0 ftKB Cement Casing; 2,745.0 ftKB Cement Casing; 2,746.0 ftKB CUT; 3,685.0 CIBP; 3,345.0 CUT; 3,340.0 SURFACE; 28.1-3,286.9 Cement Plug; 2,662.0 ftKB Cement Plug; 2,477.0 ftKB Cement Casing; 35.0 ftKB CONDUCTOR; 29.0-108.0 Tubing hanger; 23.2 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev… 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 2,745.0 10,065.0 2,111.0 5,276.2 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 92Drag up (lbs): 245Time started reciprocating: 18:30Time stopped reciprocating: 11:15Annular flow after cement job (Y/N): NCirculating BHT (F): 107Static BHT (F): 136Pressure before cementing (psi): 550Hours circulated between stages: 3.75Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): FULLTime cementing mixing started: 23:15 2/3/2004 2,746.0 6,198.0 2,111.4 3,640.8 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 92Drag up (lbs): 245Time started reciprocating: 18:30Time stopped reciprocating: 11:15Annular flow after cement job (Y/N): NCirculating BHT (F): 107Static BHT (F): 136Pressure before cementing (psi): 310Hours circulated between stages: 7.75Bbls cmt to surf: 0Method used to measure density: DensometerReturns (pct): 100Time cementing mixing started: 09:00 2/2/2004 10,065.0 10,943.0 5,276.2 5,669.7 Pre-Flush Pipe movement: Rotate & RecipDrag down (lbs): 72000Drag up (lbs): 180000Time started reciprocating: 15:30Time stopped reciprocating: 20:30Time started rotating: 16:30Time stopped rotating: 20:30Init torque (ft-lbf): 10000Max torque (ft -lbf): 10000Pressure before cementing (psi): 520Hours circulated between stages: 4Bbls cmt to surf: 0Method used to measure density: densimeterMethod used for mixing cement in this stage: BatchReturns (pct): 100Time cementing mixing started: 19:00 2/7/2004 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 2,662.0 3,345.0 2,072.1 2,376.3 Cement Plug Pump 22 Bbls 10 PPG spacer w/ Surf wash @ 2.3 BPM, 80 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 39 Bbls 15.8 PPG PTA cement w/ 5 lbs/bbls Bridge Maker II LCM @ 2.3 BPM, 235 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 6 Bbls 10 PPG spacer @ 2.3 BPM, 65 PSI. Displace w/ 34.7 Bbls 9.8 PPG brine @ 3.5 BPM, 250 PSI. Good returns throughout job. End job @ 00:49 Hrs. 2/21/2025 2,477.0 2,670.0 1,986.8 2,075.8 Cement Plug pumped 15 bbls, cleaned out to 2,477' CTMD TOC 10/24/2025 2P-419, 12/3/2025 12:13:31 PM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 Pre-Flush; 10,065.0 ftKB IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 CIBP; 10,199.3 PRODUCTION; 3,340.0- 10,065.3 TUBING PUNCH; 9,800.0 GAS LIFT; 9,776.5 Cement Plug; 7,889.0 ftKB Cement Plug; 7,889.0 ftKB Cement Casing; 2,745.0 ftKB Cement Casing; 2,746.0 ftKB CUT; 3,685.0 CIBP; 3,345.0 CUT; 3,340.0 SURFACE; 28.1-3,286.9 Cement Plug; 2,662.0 ftKB Cement Plug; 2,477.0 ftKB Cement Casing; 35.0 ftKB CONDUCTOR; 29.0-108.0 Tubing hanger; 23.2 KUP INJ 2P-419 ... WELLNAME WELLBORE2P-419 DTTMSTART JOBTYP SUMMARYOPS 7/4/2025 ACQUIRE DATA MIRU CTU 6. COMPLETE BOP TEST. RIH WITH BAKER INFLATABLE TEST PACKER. TAG TOC AT 2650' CTMD. JOB IN PROGRESS. 7/5/2025 ACQUIRE DATA START 1500 PSI MIT OF 9-5/8" SURFACE CASING @ 2639' ME (11' ABOVE TOP OF CEMENT) FAIL 1500 PSI MIT UP TO 2597' MID-ELEMENT (53' ABOVE TOP OF CEMENT) PASS 1500 PSI MIT @ 2592' MID-ELEMENT (58' ABOVE TOP OF CEMENT). COPY OF MIT FORM IN ATTACHMENTS. JOB COMPLETE. 8/3/2025 ACQUIRE DATA RIH WITH TEST PACKER. TAG CEMENT AT 2,653' PICK UP TO 2609' AND ATTEMPT TO PRESSURE UP TEST PACKER. TEST PACKER WILL NOT HOLD PRESSURE UP. RBIH W/ TEST PACKER TO 2640'. TEST PACKER WILL NOT HOLD PRESSURE UP. JOB IN PROGRESS. 8/4/2025 ACQUIRE DATA RUN INFLATABLE TEST PACKER. SET AT 2612' MID ELEMENT (37' ABOVE TOC). 1500 PSI TEST OF 9 5/8" ABOVE TEST PACKER FAILS. UNABLE TO RELEASE PRESSURE WITHOUT SHEARING TOOLS DUE TO POPPET FOR IBP BEING RUN THAT SHOULD HAVE BEEN REMOVED. POOH AND REDRESS TEST PACKER. SET TEST PACKER AT 2602' (47' ABOVE TOC) 1500 PSI TEST OF 9 5/8" ABOVE TEST PACKER FAILS. ATTEMPT TEST AT 2592' (57' ABOVE TOC) AND PACKER FAILS DURING TEST. PRIOR TO FAILING, IT APPEARED THAT PACKER WAS SLIDING DOWNHOLE. CALL ENGINEER AND DECISION MADE TO RUN ACOUSTIC LDL CALL OUT REED. PERFORM DRIFT, TAG AND FLAG WHILE STANDING BY FOR REED TO MOBILIZE. ACOUSTIC LDL 2640' - 2420'. 8/5/2025 ACQUIRE DATA DOWN LOAD ACOUSTIC LDL MEMORY SUB - GOOD DATA. DATA TO BE SENT FOR ANALYSIS. READY FOR PLAN FORWARD. 9/11/2025 ACQUIRE DATA CMIT TO 1500 PSI FOR P&A FAILED. JOB COMPLETE. 10/23/2025 ACQUIRE DATA MOVE OVER FROM 2P-429 TO 2P-419 MIRU 10/24/2025 ACQUIRE DATA STAND BY FOR CEMENT, MIRU HES CEMENTERS. PUMP 15 BBLS 15.8 PPG CEMENT PER PROCEDURE. RDMO TO 3T-619 10/26/2025 ACQUIRE DATA CMIT TO 1700psi 2.3 TOTAL BBLS DSL PUMPED 1.1 BBLS BLED BACK TEST 3 PRE T/I/O = 1625/1600/1500 INT T/I/O =1755/1745/1745 15 M T/I/O =1680/1675/1675 30 M T/I/O =1675/1660/1660 *PASS* BLEED ALL TO 0 PSI 11/8/2025 ACQUIRE DATA STATE WITNESSED TAGGED CEMENT @ 2,505' RKB, PERFORMED MIT-T/IA/OA (FAIL SEE LOG), PERFORM DRAW DOWN TEST (FAILED SEE LOG) 2P-419 Off Rig Plug and Abandon Summary of Operations 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10945' None Casing Collapse Structural Conductor Surface Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng (907) 265-6049 CTD/RWO Engineer KRU 2P-419 5671' 2477' 1987' 2477', 2662', 3345', 7889', 10199' N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: Cy.Eller@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 9893' MD and 5202' TVD 9909' MD and 5210' TVD N/A Cy Eller STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 204-017 P.O. Box 100360, Anchorage, AK 99510 50-103-20483-00 Kuparuk River Field Meltwater Oil Pool-Suspended ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst 9946' MD 108' 2352' 108' 3287' 5276'10065' 16" 9-5/8" 79' 3259' 10216-10236', 10250-10290', 10510-10570', 10644-10664' 10040' 3-1/2" 5339-5348', 5354-5371', 5467- 5493', 5527-5537' 7" Perforation Depth TVD (ft): 12/1/2025 10943'1050' 4-1/2" 5670' Packer: Baker ZXP Liner Top Packer Packer: Baker 80-40 GHB-22 Seal Assy SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-713 By Grace Christianson at 11:13 am, Nov 20, 2025 DSR-11/21/25TS 11/20/25 X VTL 11/24/2025 X X 10-407 BOP test to 2500 psig Annular preventer test to 2500 psig 12/31/2025 X 11/24/25 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 November 19, 2025 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: ConocoPhillips Alaska, Inc. hereby submits an Application for Sundry Approval to Plug & Abandon 2P- 419 (PTD # 204-017). This Sundry covers the portion to be performed on-rig by Nabors 7ES. 2P-419 was an injector that has been shut in since March of 2021. This well has been suspended with a reservoir cement plug and an intermediate cement plug. A surface shoe cement plug to isolate the C80 from the wellbore was placed on-rig with Nordic 3, but attempts to pressure test the plug have failed. A remedial cement plug was placed with coiled tubing following Sundry # 325-626, but it has also failed pressure tests. To complete the abandonment of this well, CPAI is requesting approval to remove the kill string, mill out cement from the 9-5/8 casing until injectivity is achieved, then set a cement retainer and pump cement. After remediating the surface shoe cement plug, we plan to run a kill string and complete the surface cement plug. If you have any questions or require any further information, please contact me at 907-265-6049. Cy Eller Rig Workover Engineer CPAI Drilling and Wells 2P-419 P&A Procedure PTD #204-017 Page 2 of 4 Pre-Rig Work Remaining 1. Prepare well for rig arrival Rig Work MIRU 1. MIRU Nabors 7ES on 2P-419. No BPV will be set for MIRU due to Nabors 7ES internal risk assessment. 2. Record shut in pressures on the kill string and kill string x SC annulus. Circulate seawater and complete 30-minute NFT. Verify well is dead. 3. ND Tree, NU BOPE and test to 250/2,500 psi. Test annular 250/2,500 psi. a. No BPV will be set for ND/NU due to two tested mechanical plugs in wellbore providing barrier to reservoir in addition to four cement plugs. Retrieve Kill String 4. MU landing joint and BOLDS. 5. Pull and lay down 4-1/2 kill string. Remove Cement from 9-5/8 Casing 6. MU cement milling BHA. 7. PU DP, RIH to top of cement in 9-5/8 casing. a. Anticipated TOC from slickline tag is 2,505 RKB. 8. Mill cement from 9-5/8 casing until injectivity is achieved. 9. TOOH and LD milling BHA. Set Cement Retainer 10. MU and RIH with cement retainer for 9-5/8 casing. a. Set depth will be determined by the depth that injectivity is achieved. 11. Pump cement through retainer. Release from retainer and place 50 of cement on top of retainer. a. Cement volume will be determined by the depth that injectivity is achieved. Test Cement Plug 12. Wait on cement. 13. Tag cement and PT to 1,500 psi for 30 minutes with State witness. Execute Final Abandonment Plug 14. POOH laying down drillpipe. 15. TIH with kill string. 16. Land kill string in casing hanger profile. 17. Circulate cement surface to surface until full cement returns observed. a. Cement volume will be determined by the depth that the shoe plug is tagged. 2P-419 P&A Procedure PTD #204-017 Page 3 of 4 RDMO 18. Perform NFT. ND BOPE. NU tree. a. This step may be performed before pumping final abandonment plug for operational efficiency. 19. RDMO. Execute Final Abandonment Surface Excavation 1. DHD perform drawdown test of workstring and annulus. 2. Bleed off any trapped pressure from dry hole tree. 3. Remove tree in preparation for excavation and casing cut. 4. Have shoring box installed during excavation as needed to prevent loose ground from falling into excavation. 5. Cut off wellhead and all casing strings at 4 feet below original ground level. 6. Perform top job if needed to ensure cement is in all casing strings. AOGCC witness and photo document required. 7. Send casing head with stub to materials shop. Photo document. 8. Weld ¼ thick cover plate (16 OD) over all casing strings with the following information bead welded into the top. Photo document and AOGCC witness required. a. ConocoPhillips b. KRU 2P-419 c. PTD# 204-017 d. API# 50-103-20483-00 9. Remove cellar. Backfill cellar with gravel as needed. Backfill remaining hole to ground level. 10. Obtain site clearance approval from AOGCC. 11. RDMO. 12. Report that final P&A has been completed to AOGCC. Photo document final location condition after completing work. General Well Information: Estimated Start Date: 12/1/2025 Current Operations: Suspended Well Type: Injector Wellhead Type: FMC Gen V. 11 5M casing head top flange. 11 5M tubing head top flange. 4- 1/16 5M tree. Scope of Work: Pull 4-1/2 kill string. Mill cement from 9-5/8 casing until injectivity is achieved. Set cement retainer in 9-5/8 casing and pump cement through retainer. Run 4- 1/2 kill string and circulate cement to surface. Execute final abandonment. BOP Configuration: Annular / Pipe Rams / Blind Rams / Pipe Rams 2P-419 P&A Procedure PTD #204-017 Page 4 of 4 Well Data: Meltwater Formation: Reservoir pressure 7/31/2023 = 2912 psi @ 5196 TVD MASP = 2392 psi (using 0.1 psi/ft gradient) / 0 psi (Cemented) C-80 Formation: OA Pressure = 199 psi (11/5/2022) (Fluid packed with diesel) MASP = 783 psi (using 0.1 psi/ft gradient) / 0 psi (Cemented) CTU Remedial Surface Plug: TOC = 2,505 RKB (slickline tag) Most recent PT attempt = Failed (11/8/2025) Personnel: Workover Engineer: Cy Eller (907-265-6049 / Cy.Eller@conocophillips.com) Intervention Engineer: Erica Livingston 2P-419 Current Schematic COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread Conductor 108 108 16 15.06 62.5 H-40 Welded Surface Casing 3287 2352 9 5/8 8.83 40 L-80 BTC Production Casing Top - 3340 Btm - 10065 Top - 2374 Btm - 5276 7 6.28 26 L-80 BTC-M Production Liner Top - 9893 Btm - 10943 Top - 5202 Btm - 5670 3 1/2 2.99 9.2 L-80 SLHT Kill String 2448 1974 4 1/2 3.96 12.6 L-80 NSCT Tubing Top - 3685 Btm- 9946 Top - 2529 Btm - 5225 4 1/2 3.96 12.6 L-80 NSCT/IBTM Surface Casing 3287' RKB Production Casing 10065' RKB Conductor Production Casing Cement Stage 1 Calculated TOC: 8002' RKB Surface Casing TOC: Surface Production Liner 10943' RKB T-3 Perfs 10216' RKB - 10664' RKB Production Liner Calculated TOC: 9893' RKB Production Casing Cement Stage 2 Calculated TOC: 4561' RKB Calculated BOC: 6199' RKB Plug #1 -Reservoir TOC 10,140' RKB CIBP 10,200' RKB Plug #2 - Intermediate TOC 7,889' RKB BOC 9,800' RKB Tubing Cut: 3,685' RKB CIBP CIBP 3345' RKB Production Casing Cut: 3,340' RKB Surface Shoe Cement Plug Date Placed: 2/22/2025 TOC: 2,662' RKB 2nd Surface Shoe Cement Plug Date Placed: 10/24/2025 Slickline Tagged TOC: 2,505' RKB 2P-419 Proposed P&A Schematic COMPLETION INFO MD (ft RKB) TVD (ft RKB) OD (in) Nom. ID (in) Weight (lb/ft)Grade Thread Conductor 108 108 16 15.06 62.5 H-40 Welded Surface Casing 3287 2352 9 5/8 8.83 40 L-80 BTC Production Casing Top - 3340 Btm - 10065 Top - 2374 Btm - 5276 7 6.28 26 L-80 BTC-M Production Liner Top - 9893 Btm - 10943 Top - 5202 Btm - 5670 3 1/2 2.99 9.2 L-80 SLHT Kill String ~2750 ~2113 4 1/2 3.96 12.6 L-80 NSCT Tubing Top - 3685 Btm- 9946 Top - 2529 Btm - 5225 4 1/2 3.96 12.6 L-80 NSCT/IBTM Surface Casing 3287' RKB Production Casing 10065' RKB Conductor Production Casing Cement Stage 1 Calculated TOC: 8002' RKB Surface Casing TOC: Surface Production Liner 10943' RKB T-3 Perfs 10216' RKB - 10664' RKB Production Liner Calculated TOC: 9893' RKB Production Casing Cement Stage 2 Calculated TOC: 4561' RKB Calculated BOC: 6199' RKB Plug #1 -Reservoir TOC 10,140' RKB CIBP 10,200' RKB Plug #2 - Intermediate TOC 7,889' RKB BOC 9,800' RKB Tubing Cut: 3,685' RKB CIBP CIBP 3345' RKB Production Casing Cut: 3,340' RKB Surface Shoe Cement Plug Date Placed: 2/22/2025 Cmt Retainer Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB (Tagged TOC) 7,889.0 2P-419 3/30/2024 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Update post RWO 2P-419 3/7/2025 rogerba Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 3,340.0 10,065.3 5,276.4 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth 2,447.8 Set Depth 1,973.9 String Max No 4 1/2 Tubing Description Tubing Kill String Wt (lb/ft) 12.60 Grade L-80 Top Connection NSCT ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 2,416.7 1,960.4 64.22 Shoe - Mule 4.500 4 1/2" 12.6 ppf, L-80 NSCT Tubing Mule Shoe 3.958 Top (ftKB) 3,685.0 Set Depth 9,946.1 Set Depth 5,225.4 String Max No 4 1/2 Tubing Description Tubing Completion Lower Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.4 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.1 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.5 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 3,340.0 2,374.2 64.75 CUT 2/19/2025 6.800 3,345.0 2,376.3 64.75 CIBP CIBP set 2/18/2025 0.000 3,685.0 2,528.7 61.77 CUT WELLTEC MECHANICAL TBG CUT AT 3685' RKB 3/31/2024 3.958 9,800.0 5,162.8 65.09 TUBING PUNCH 3' TUBING PUNCH, 2", 7 GRAM, 6 SPF, 18 0.61" HOLES 3/23/2024 3.958 10,199.3 5,332.3 65.08 CIBP Set 2.62" CIBP (mid-element @ 10200' RKB) OAL=1.37' 3/9/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 35.0 3,287.0 35.0 2,351.6 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 105Drag up (lbs): 125Time started reciprocating: 21:30Time stopped reciprocating: 02:37Annular flow after cement job (Y/N): NCirculating BHT (F): 65Static BHT (F): 51Pressure before cementing (psi): 375Hours circulated between stages: 3Bbls cmt to surf: 136.6Method used to measure density: DensometerMethod used for mixing cement in this stage: TubReturns (pct): FULLTime cementing mixing started: 01:30 1/24/2004 2P-419, 11/19/2025 4:40:42 PM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 Pre-Flush; 10,065.0 ftKB IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 CIBP; 10,199.3 PRODUCTION; 3,340.0- 10,065.3 TUBING PUNCH; 9,800.0 GAS LIFT; 9,776.5 Cement Plug; 7,889.0 ftKB Cement Plug; 7,889.0 ftKB Cement Casing; 2,745.0 ftKB Cement Casing; 2,746.0 ftKB CUT; 3,685.0 CIBP; 3,345.0 CUT; 3,340.0 SURFACE; 28.1-3,286.9 Cement Plug; 2,662.0 ftKB Cement Plug; 2,477.0 ftKB Cement Casing; 35.0 ftKB CONDUCTOR; 29.0-108.0 Tubing hanger; 23.2 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 2,745.0 10,065.0 2,111.0 5,276.2 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 92Drag up (lbs): 245Time started reciprocating: 18:30Time stopped reciprocating: 11:15Annular flow after cement job (Y/N): NCirculating BHT (F): 107Static BHT (F): 136Pressure before cementing (psi): 550Hours circulated between stages: 3.75Method used to measure density: DensometerMethod used for mixing cement in this stage: BatchReturns (pct): FULLTime cementing mixing started: 23:15 2/3/2004 2,746.0 6,198.0 2,111.4 3,640.8 Cement Casing Pipe movement: ReciprocatingDrag down (lbs): 92Drag up (lbs): 245Time started reciprocating: 18:30Time stopped reciprocating: 11:15Annular flow after cement job (Y/N): NCirculating BHT (F): 107Static BHT (F): 136Pressure before cementing (psi): 310Hours circulated between stages: 7.75Bbls cmt to surf: 0Method used to measure density: DensometerReturns (pct): 100Time cementing mixing started: 09:00 2/2/2004 10,065.0 10,943.0 5,276.2 5,669.7 Pre-Flush Pipe movement: Rotate & RecipDrag down (lbs): 72000Drag up (lbs): 180000Time started reciprocating: 15:30Time stopped reciprocating: 20:30Time started rotating: 16:30Time stopped rotating: 20:30Init torque (ft-lbf): 10000Max torque (ft -lbf): 10000Pressure before cementing (psi): 520Hours circulated between stages: 4Bbls cmt to surf: 0Method used to measure density: densimeterMethod used for mixing cement in this stage: BatchReturns (pct): 100Time cementing mixing started: 19:00 2/7/2004 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 2,662.0 3,345.0 2,072.1 2,376.3 Cement Plug Pump 22 Bbls 10 PPG spacer w/ Surf wash @ 2.3 BPM, 80 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 39 Bbls 15.8 PPG PTA cement w/ 5 lbs/bbls Bridge Maker II LCM @ 2.3 BPM, 235 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 6 Bbls 10 PPG spacer @ 2.3 BPM, 65 PSI. Displace w/ 34.7 Bbls 9.8 PPG brine @ 3.5 BPM, 250 PSI. Good returns throughout job. End job @ 00:49 Hrs. 2/21/2025 2,477.0 2,670.0 1,986.8 2,075.8 Cement Plug pumped 15 bbls, cleaned out to 2,477' CTMD TOC 10/24/2025 2P-419, 11/19/2025 4:40:42 PM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 Pre-Flush; 10,065.0 ftKB IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 CIBP; 10,199.3 PRODUCTION; 3,340.0- 10,065.3 TUBING PUNCH; 9,800.0 GAS LIFT; 9,776.5 Cement Plug; 7,889.0 ftKB Cement Plug; 7,889.0 ftKB Cement Casing; 2,745.0 ftKB Cement Casing; 2,746.0 ftKB CUT; 3,685.0 CIBP; 3,345.0 CUT; 3,340.0 SURFACE; 28.1-3,286.9 Cement Plug; 2,662.0 ftKB Cement Plug; 2,477.0 ftKB Cement Casing; 35.0 ftKB CONDUCTOR; 29.0-108.0 Tubing hanger; 23.2 KUP INJ 2P-419 ... WELLNAME WELLBORE2P-419 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10945' None Casing Collapse Structural Conductor Surface Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10/20/2025 10943'1050' 4-1/2" 5670' Packer: Baker ZXP Liner Top Packer Packer: Baker 80-40 GHB-22 Seal Assy SSSV: None Perforation Depth MD (ft): L-80 3259' 10216-10236', 10250-10290', 10510-10570', 10644-10664' 10040' 3-1/2" 5339-5348', 5354-5371', 5467- 5493', 5527-5537' 7" Perforation Depth TVD (ft): 108' 3287' 5276'10065' 16" 9-5/8" 79' 9946' MD 108' 2352' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 204-017 P.O. Box 100360, Anchorage, AK 99510 50-103-20483-00 Kuparuk River Field Meltwater Oil Pool-Suspended AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 9893' MD and 5202' TVD 9909' MD and 5210' TVD N/A Jill Simek Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: Jill.Simek@conocophillips.com (907) 263-4131 Staff Interventions Engineer KRU 2P-419 5671' 2662' 2072' 2662', 3345', 7889', 10199' N/A Pe ss ell Cl L S A C t P N/A i t d f W s No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:57 pm, Oct 13, 2025 325-626 DSR-10/15/25 Abandonment must be completed by 12/31/25. AOGCC witness tag TOC, MIT of casing, and draw down test (DDT) of casing post-cement plug #4 with results submitted to the AOGCC. AOGCC witness casing cuts before any top job commences. AOGCC witness marker cap install before backfilling. Photo evidence of cement tops post-cut 10-407 A.Dewhurst 13OCT25 X J.Lau 10/14/25 X 10/16/2025 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Commissioner, State of Alaska October 8, 2025 Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: Please find attached, the 10-403 Application for Sundry Approval for ConocoPhillips Alaska, Inc. well KRU 2P-419 (PTD# 204-017). This 10-403 is being submitted to request procedure changes to the existing Sundry Approved P&A procedure (Sundry# 325-300). If you have any questions, please contact me at 263-4131. Sincerely, Jill Simek Staff Well Interventions Engineer 2P-419 Plug and Abandon Revised Procedure PTD #204-017 Sundry #325-300 Page 1 of 2 2P-419 is a suspended injector, iden ed for P&A as part of ConocoPhillips 2P pad abandonment program. Currently, the well is suspended with 2 cement plugs. A third cement plug was a empted, on-rig, to isolate the C80 from the wellbore; however, this plug has a slow leak and will require remedia on. During job planning, risks were iden ed in the placement of the BiSN Wel-Lok plug at high wellbore devia on (62deg). Unable to mi gate risk to an acceptable level, ConocoPhillips proposes the following revised procedure. This revised procedure eliminates the Wel-Lok BiSN plug steps and replaces with cemen ng steps. Changes are highlighted in green below. C80 Cement Plug Attempt (Rig): Summarized Operational Procedure o 39 BBL 15.8 Class G Cement with 5lbs/bbl Bridgemaker II LCM o Displace with 9.8 PPG Brine o Planned TOC = 2857ft KB Result o Wash in hole, tag 2,662 RKB 10K WOB. Circ out contaminated cement. o Attempt to pressure test (1500psi). Failed. Last Pressure Test: 9/11/2025: CMIT to 1500psi Pressured to 1500 psi w/ 0.2 bbls DSL, Initial = 1500/1650 15 min = 1450/1600 30 min = 1420/1550 45 min = 1375/1500 Procedure: Prepare Casing and Place New Cement (Coil) 1. MIRU. 2. RIH with underreamer. Underream plug setting depth. Confirm TOC. 3. RIH with coil and place ~160ft cement plug, ~12bbls, leaving TOC ~2502ft KB. 4. RDMO. Ready for Slickline. Place Wel-Lok (Eline & Pumping) 5. MIRU. 6. Pump steel beads down killstring x casing annulus, to TOC at 2,662ft KB. 7. RIH with eline and Wel-Lok heater. Tag steel beads. 8. Pump Wel-Lok beads down killstring x casing annulus. 9. Activate Wel-Lok heater to melt beads, placing ~5-6ft BiSN plug in 9-5/8 casing. 10. RDMO. Ready for Slickline. Tag and Pressure Test (Slickline) 11. Notify the AOGCC Inspector of timing for pressure test (submit AOGCC Test Witness Notification Form 24hrs in advance of witness). 12. MIRU. 13. RIH and tag TOC (witnessed). 14. Perform MIT on casing (witnessed). 15. Perform DDT on casing (witnessed). 16. RDMO. Surface Cement Plug (Pumping) 17. MIRU 18. Pump ~191bbls permafrost cement in kill string and surface casing. 19. RDMO. Wait on cement. 2P-419 Plug and Abandon Revised Procedure PTD #204-017 Sundry #325-300 Page 2 of 2 Wellhead Excavation / Final P&A: 20. Confirm tubing and annulus pressures are at 0psi. 21. Notify the AOGCC Inspector of timing for surface plug witness and marker plate installation (submit AOGCC Test Witness Notification Form 24hrs in advance of witness). 22. Remove the tree, in preparation for the excavation and casing cut. 23. Excavate and remove wellhead and all casing strings at 4 feet below original ground level. 24. Verify that cement is at surface in all strings. Perform cement top off job(s) if required. AOGCC witness and photo document required. 25. Send the casing head w/ stub to materials shop. Photo document. 26. Weld ¼ thick cover plate (16 O.D.) over all casing strings with the following information bead welded into the top. Photo document. AOGCC Witness Required. ConocoPhillips KRU 2P-419 PTD #: 204-017 API #: 50-103-20483-00-00 27. Remove Cellar. Back fill cellar with gravel/fill as needed. Back fill remaining hole to ground level. 28. Obtain site clearance approval from AOGCC. RDMO. Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 P&A Schematic - Current Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 1 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3 KB T-3 Peforations: @ 10,216' 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB (2351' TVD) Production Tubing: 4.5 x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943 KB Plug #1 Reservoir TOC @ 10140' RKB BOC (CIBP) @ 10200' RKB C80 @ 3530' KB C80 @ 3530' KB Plug #3 - Surface Shoe TOC @ 2662' RKB BOC (CIBP) @ 3345' RKB 2 1 Plug #2 Intermediate TOC @ 7889' RKB BOC @ 9800' RKB 4 ½ Kill String set at 2448' RKB Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 P&A Schematic - Proposed Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 1 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3 KB T-3 Peforations: @ 10,216' 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB (2351' TVD) Production Tubing: 4.5 x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943 KB Plug #1 Reservoir TOC @ 10140' RKB BOC (CIBP) @ 10200' RKB C80 @ 3530' KB C80 @ 3530' KB Plug #3 - Surface Shoe TOC @ 2662' RKB BOC (CIBP) @ 3345' RKB 2 1 Plug #2 Intermediate TOC @ 7889' RKB BOC @ 9800' RKB 4 ½ Kill String set at 2448' RKB Plug #5 TOC @ Surface BOC ~2448' RKB Plug #4 TOC ~2502' RKB BOC @ 2662' RKB C:\Users\grgluyas\AppData\Local\Microsoft\Windows\INetCache\Content.Outlook\4MY18Q6V\2025-08-04_23087_KRU_2P-419_LeakPointSurvey_Transmittal.docx DELIVERABLE DISCRIPTION Ticket # Field Well # API # Log Description Log Date 23087 KRU 2P-419 50-103-20483-00 LeakPoint Survey 04-Aug-25 DELIVERED TO Company & Address DIGITAL FILE # of Copies LOG PRINTS # of Prints CD’s # of Copies 1 AOGCC Attn: Natural Resources Technician 333 W. 7th Ave., Suite 100 Anchorage, Ak. 99501-3539 Delivered By: CPAI Sharefile ______________________________ _____________________________________ Date received Signature ______________________________ ______________________________________ PLEASE RETURN COPY VIA EMAIL TO: DIANE.WILLIAMS@READCASEDHOLE.COM READ CASED HOLE, INC., 4141 B STREET, SUITE 308, ANCHORAGE, AK 99503 PHONE: (907)245-8951 E-MAIL :READ-Anchorage@readcasedhole.com WEBSITE :WWW.READCASEDHOLE.COM Originated: Delivered to:18-Jun-25Halliburton Alaska Oil and Gas Conservation Comm.Wireline & Perforating Attn.: Natural Resource TechnicianAttn: Fanny Haroun 333 West 7th Avenue, Suite 1006900 Arctic Blvd. Anchorage, Alaska 99501Anchorage, Alaska 99518Office: 907-275-2605FRS_ANC@halliburton.comThe technical data listed below is being submitted herewith. Please address any problems orconcerns to the attention of the sender aboveWELL NAME API # SERVICE ORDER # FIELD NAME JOB TYPE DATA TYPE LOGGING DATE PRINTS # DIGITAL # E SET#1 2P-419 50-103-20483-00 910080528 Kuparuk River Multi Finger Caliper Field & Processed 7-Jun-25 0 12 2P-429 50-103-20378-00 910080397 Kuparuk River Multi Finger Caliper Field & Processed 8-Jun-25 0 13 2T-38A 50-103-20229-01 910106462 Kuparuk River Plug Setting Record Field- Final 8-Jun-25 0 14 2Z-07 50-029-20946-00 910026798 Kuparuk River Plug Setting Record Field- Final 10-May-25 0 15 3K-20 50-029-23019-00 910080196 Kuparuk River Packer Setting Record Field- Final 18-May-25 0 16 3N-12 50-029-21582-00 910080396 Kuparuk River Multi Finger Caliper Field & Processed 3-Jun-25 0 17 3N-12 50-029-21582-00 910080396 Kuparuk River Plug Setting Record Field- Final 3-Jun-25 0 18 3N-12 50-029-21582-00 910080396 Kuparuk River Plug Setting Record Field- Final 4-Jun-25 0 19 3N-12 50-029-21582-00 910080396 Kuparuk River Plug Setting Record Field- Final 6-Jun-25 0 110PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF:Fanny Haroun, Halliburton Wireline & Perforating, 6900 Arctic Blvd., Anchorage, AK 99518FRS_ANC@halliburton.comDate:Signed:Transmittal Date:T40597T40598T40599T40600T40601T40602T40602T40602T40602204-017201-102197-205183-064201-088186-0796/20/2025Gavin GluyasDigitally signed by Gavin Gluyas Date: 2025.06.20 08:47:18 -08'00'2P-41950-103-20483-00 910080528Kuparuk RiverMulti Finger CaliperField & Processed7-Jun-2501204-017 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" B 108' 9-5/8" L-80 2352' 7" L-80 5276' 3-1/2" L-80 5670' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 51.7 bbl Class G6.125" TUBING RECORD 223 sx Class G, 209 sx Class G8.5" 9946'4-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 2/24/2025 204-017/ 324-710/ 324-161 50-103-20483-00-00 KRU 2P-419888' FNL, 2148' FWL, Sec. 17, T8N, R7E, UM 1962' FSL, 287' FEL, Sec. 19, T8N, R7E, UM L32092/ 32409 1/21/2004 10945' MD/ 5671' TVD 2662' MD / 2072' TVD P.O. Box 100360, Anchorage, AK 99510-0360 444108 5868988 2587' FSL, 127' FWL, Sec. 20, T8N, R7E, UM CASING WT. PER FT.GRADE 2/5/2004 CEMENTING RECORD 5861918 1399' MD/ 1355' TVD SETTING DEPTH TVD 5861297 TOP HOLE SIZE AMOUNT PULLED 442058 441641 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A 9. Ref Elevations: KB: 28' BOTTOM DEPTH SET (MD) 9893' MD/ 5202' TVD PACKER SET (MD/TVD) 42" 12.25" 110 sx LiteCrete 28'396 sx AS Lite, 297 sx LiteCrete 9.3# 29' 9893' 3287'28' 29' If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): Kuparuk River Field/Meltwater Oil Pool- Suspended ADL0373112, ADL0389058 Flow Tubing 7889-9803' SUSPENDED 10216-10236' MD and 5339-5348' TVD 10250-10290' MD and 5354-5371' TVD 10510-10570' MD and 5467-5493' TVD 10644-10664' MD and 5527-5537' TVD Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 26# 10943' 2374' 5202' 62.5# 40# 108' Sr Res EngSr Pet GeoSr Pet Eng None Oil-Bbl: Water-Bbl: 51 bbl 15.8 ppg Cement 2662-3345' 39 bbl 15.8 ppg PTA Cement w 5 lbs/bbl Bridgemaker II LCM Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: 3340' 10065' SIZE Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 11:53 am, Mar 25, 2025 Suspend 2/24/2025 JSB RBDMS JSB 032825 xGDSR-4/7/25VTL 7/30/2025 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1399' 1355' Top of Productive Interval 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Shane Germann Digital Signature with Date:Contact Email: Shane.Germann@conocophillips.com Contact Phone: 263-4597 Senior CTD/RWO Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS Authorized Title: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Authorized Name and N/A - Suspended N/A - Suspended INSTRUCTIONS Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Shane Germann DN: O=ConocoPhillips, CN=Shane Germann, E= shane.germann@conocophillips.com Reason: I have reviewed this document Location: Date: 2025.03.25 08:33:11-08'00' Foxit PDF Editor Version: 13.0.0 Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB (Tagged TOC) 7,889.0 2P-419 3/30/2024 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Update post RWO 2P-419 3/7/2025 rogerba Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 3,340.0 10,065.3 5,276.4 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth … 2,447.8 Set Depth … 1,973.9 String Max No… 4 1/2 Tubing Description Tubing – Kill String Wt (lb/ft) 12.60 Grade L-80 Top Connection NSCT ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 2,416.7 1,960.4 64.22 Shoe - Mule 4.500 4 1/2" 12.6 ppf, L-80 NSCT Tubing Mule Shoe 3.958 Top (ftKB) 3,685.0 Set Depth … 9,946.1 Set Depth … 5,225.4 String Max No… 4 1/2 Tubing Description Tubing – Completion Lower Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.4 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.1 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.5 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 3,340.0 2,374.2 64.75 CUT 2/19/2025 6.800 3,345.0 2,376.3 64.75 CIBP CIBP set 2/18/2025 0.000 3,685.0 2,528.7 61.77 CUT WELLTEC MECHANICAL TBG CUT AT 3685' RKB 3/31/2024 3.958 9,800.0 5,162.8 65.09 TUBING PUNCH 3' TUBING PUNCH, 2", 7 GRAM, 6 SPF, 18 0.61" HOLES 3/23/2024 3.958 10,199.3 5,332.3 65.08 CIBP Set 2.62" CIBP (mid-element @ 10200' RKB) OAL=1.37' 3/9/2024 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 2,662.0 3,345.0 2,072.1 2,376.3 Cement Plug Pump 22 Bbls 10 PPG spacer w/ Surf wash @ 2.3 BPM, 80 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 39 Bbls 15.8 PPG PTA cement w/ 5 lbs/bbls Bridge Maker II LCM @ 2.3 BPM, 235 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 6 Bbls 10 PPG spacer @ 2.3 BPM, 65 PSI. Displace w/ 34.7 Bbls 9.8 PPG brine @ 3.5 BPM, 250 PSI. Good returns throughout job. End job @ 00:49 Hrs. 2/21/2025 2P-419, 3/19/2025 10:55:03 AM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 CIBP; 10,199.3 PRODUCTION; 3,340.0- 10,065.3 TUBING PUNCH; 9,800.0 GAS LIFT; 9,776.5 Cement Plug; 7,889.0 ftKB Cement Plug; 7,889.0 ftKB CUT; 3,685.0 CIBP; 3,345.0 CUT; 3,340.0 SURFACE; 28.1-3,286.9 Cement Plug; 2,662.0 ftKB CONDUCTOR; 29.0-108.0 Tubing hanger; 23.2 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev… 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 Well Final P&A Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3’ KB T-3 Peforations: @ 10,216' – 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB (2351' TVD) Production Tubing: 4.5” x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 /ƚĞŵĞƉƚŚͲƚŽƉƐ ;<Ϳ ϭ 'D' Esdh/E',E' Z Ϯϯ͘ϮΖ Ϯ ĂƐƚ/ƌŽŶƌŝĚŐĞWůƵŐ ϯϯϰϱ͘ϬΖ ϯ ZK^^Ks Zϰ͘ϱΗdžϯ͘ϱΗdh/E'ϵ͕ϴϯϬ͘ϯΖ ϰ < ZDh^>//E'^> s ϵ͕ϴϳϵ͘ϭΖ ϱ < ZyW,Z>/E ZdKW /^K>d/KEW< Z ϵ͕ϴϵϯΖ ϲ DKΖΖE/WW> ǁͬϮ͘ϳϱΗEK'K WZK&/> ϵ͕ϴϵϱ͘ϭΖ ϳ < Z'ͲϮϮ>KdKZ ϵ͕ϵϬϴ͘ϮΖ ϴ < ZϴϬͲϰϬ',ͲϮϮ^ > ^^ D>zǁͬ,>&Dh> ^,K ϵ͕ϵϬϵ͘ϰΖ ϵ Z^W<K&&^ >E/WW> ϵ͕ϵϭϭ͘ϵΖ ϭϬ < Z&> yͲ>K<>/E Z,E' Z ϵ͕ϵϭϰ͘ϳΖ ϭϭ < ZϴϬͲϰϬ^ >KZ yd E^/KE ϵ͕ϵϮϰ͘ϳΖ ϭϮ ZK^^Ks Zh^,/E'ϵ͕ϵϰϯ͘ϯΖ 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943’ KB Plug #1 – Reservoir TOC ±10170' RKB C80 @ 3530' KB C80 @ 3530' KB 4-½” Kill String set at 2448' RKB 2 1 Plug #2 – Intermediate TOC ±7889' RKB BOC @ ±9800' RKB Plug #3 – Surface Shoe TOC ±2662' RKB (2072' TVD) BOC @ ±3345' RKB Page 1/7 2P-419 Report Printed: 3/19/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/16/2025 00:00 2/16/2025 03:00 3.00 MIRU, MOVE MOB P Warm up moving system hydraulics. Jack up rig. Back off 2P-419. Stage rig on pad. Unload old tree. Clean up area in front of well. Lay pit liner & T mats at 2P-419. 0.0 0.0 2/16/2025 03:00 2/16/2025 07:00 4.00 MIRU, MOVE MOB P Spot sub over 2P-419. Shim & berm rig. Center and level rig over well. 0.0 0.0 2/16/2025 07:00 2/16/2025 13:30 6.50 MIRU, MOVE MOB T Inadequate pad prep. Nordic unable to level rig over well. Off by 4-6". Pull rig back off well. Call out survey crew to re- shoot the pad. Toolhouse called roads and pads to come level up the pad in front of 2P-419. Level up in front of 2P- 417 (last well in program). 0.0 0.0 2/16/2025 13:30 2/16/2025 14:30 1.00 MIRU, MOVE MOB P Spot sub over 2P-419. Shim & berm rig. Center and level rig over well. 0.0 0.0 2/16/2025 14:30 2/16/2025 16:30 2.00 MIRU, WELCTL MOB P Spot auxiliary equipment. Take initial RKB's and pressures. Initial Pressures (T/IA/OA) = 80 / 80 / 190 psi. RU bleed trailer to OA. Bleed off OA. Stage contingency wellhead equipment behind cellar (dry hole tree + DSA). Complete rig acceptance check list. Accept rig @ 16:00. 0.0 0.0 2/16/2025 16:30 2/16/2025 20:30 4.00 MIRU, WELCTL RURD P Load 9.8# brine into pits. Finish spotting in support equipment. RU hardline to kill tanks and cuttings tank. Build and warm up 35 bbl Deep Clean pill. ** Tree missing outlet flange on wing valve, wait for hardline crew to deliver and install on tree ** 0.0 0.0 2/16/2025 20:30 2/16/2025 21:00 0.50 MIRU, WELCTL SFTY P PJSM on well kill. 0.0 0.0 2/16/2025 21:00 2/16/2025 21:30 0.50 MIRU, WELCTL PRTS P PT circ manifold & hard line T/ 2,500 PSI. 0.0 0.0 2/16/2025 21:30 2/16/2025 22:15 0.75 MIRU, WELCTL KLWL P Pump 30 bbls warm Deep Clean. Chase with 285 Bbls 9.8# brine @ 4 BPM / ICP = 534 psi, FCP = 500 psi. Circulate until have clean 9.8# brine around. 0.0 0.0 2/16/2025 22:15 2/16/2025 23:15 1.00 MIRU, WELCTL OWFF P OWFF - 30 Min, IA still flowing 0.0 0.0 2/16/2025 23:15 2/17/2025 00:00 0.75 MIRU, WELCTL CIRC P Circulate 125 bbls 9.8# NACL @ 598 psi 0.0 0.0 2/17/2025 00:00 2/17/2025 01:00 1.00 MIRU, WELCTL OWFF P OWFF 30 min @ WH, NF 0.0 0.0 2/17/2025 01:00 2/17/2025 01:30 0.50 MIRU, WELCTL MPSP P Set BPV w/ test dart. 0.0 0.0 2/17/2025 01:30 2/17/2025 03:30 2.00 MIRU, WHDBOP NUND P ND and hang old tree. Inspect hanger neck threads. Function LDS. 0.0 0.0 2/17/2025 03:30 2/17/2025 05:00 1.50 MIRU, WHDBOP NUND P N/U BOP. Install flow niipple. M/U trip hose. 0.0 0.0 2/17/2025 05:00 2/17/2025 06:00 1.00 MIRU, WHDBOP RURD P R/U, testing equipment, Fill stack w/ fresh water. 0.0 0.0 2/17/2025 06:00 2/17/2025 07:00 1.00 MIRU, WHDBOP PRTS P Shell test BOP. 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 2/24/2025 Page 2/7 2P-419 Report Printed: 3/19/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/17/2025 07:00 2/17/2025 13:00 6.00 MIRU, WHDBOP BOPE P Initial BOPE test, Tested BOPE at 250/2500 PSI for 5 Min each, Tested UVBR w/ 3 1/2" and 4 1/2" TJ. Test annular w/ 3 1/2" & 7” test joints. Test LPR w/ 7" TJ. Test blinds rams. Choke valves #1 to #13, upper and lower top drive well control valves. Test 3 1/2" IF FOSV and IBOP. Test 2 7/8" Pac HT FOSV and IBOP. Test 3 ½” EUE FOSV. Test 2" rig floor Demco kill valve MM #13. Test manual and HCR kill valves & manual and HCR choke valves. Test two ea 2 1/6" gate auxiliary valves below LPR. Test hydraulic and manual choke valves to 1500 PSI and demonstrate bleed off. Perform accumulator test. Initial pressure = 2950 PSI, after closure (drawdown) = 1600 PSI, 200 PSI attained = 23 sec, full recovery attained = 124 sec. UVBR's = 5 sec, LVBR’s = 5 Annular = 16 sec. Simulated blinds = 5 sec. HCR choke & kill= 1 sec each. 4 back up nitrogen bottles average = 1950 PSI. Test gas detectors, PVT and flow show. Test witnessed waived by AOGCC - Adam Earl. 0.0 0.0 2/17/2025 13:00 2/17/2025 13:30 0.50 MIRU, WHDBOP RURD P Blowdown. R/D testing equipment. Clean and clear rig floor. 0.0 0.0 2/17/2025 13:30 2/17/2025 14:00 0.50 MIRU, WHDBOP MPSP P Pull BPV + Test Dart. 0.0 0.0 2/17/2025 14:00 2/17/2025 15:00 1.00 COMPZN, CSGRCY PULL P MU 4 1/2" Landing Joint (3 1/2" IF Joint w/ NSCT bottleneck XO). Thread into tubing hanger. Count threads. Ensure fully engaged. Tight fit w/ bottleneck clearance. Screw in TD. Set 10K down. BOLDS. Pull hanger to rig floor. Unseat @ 70K. Drag to floor @ 65K. 3,685.0 3,653.0 2/17/2025 15:00 2/17/2025 16:00 1.00 COMPZN, CSGRCY CIRC P Circulate B/U // 4 bpm @ 55 psi. 6 BPM @ 120 psi. 3,653.0 3,653.0 2/17/2025 16:00 2/17/2025 20:00 4.00 COMPZN, CSGRCY PULL P Pull production 4.5" tubing from pre-rig cut @ 3,685', pipe clean. L/D 118 full joints of 4 1/2" NSCT Tubing. L/D Cut Joint. Length = 14.3'. Kick out cut joint and joint with tubing punch holes. 3,653.0 0.0 2/17/2025 20:00 2/17/2025 21:00 1.00 COMPZN, CSGRCY RURD P Clean and clear rig floor. Load Yellow Jacket tools. Change pipe handling equipment to 3 1/2". Load additional 3 1/2" DP Joints. 0.0 0.0 2/17/2025 21:00 2/17/2025 22:00 1.00 COMPZN, CSGRCY BHAH P MU BHA #1 (7" CIBP). 0.0 10.0 2/17/2025 22:00 2/18/2025 00:00 2.00 COMPZN, CSGRCY TRIP P TIH w/ CIBP to 2,985''.Stack out unable to pass, pick up losse hole to 2,975' prep to pull out of hole for cleanout 10.0 2,985.0 2/18/2025 00:00 2/18/2025 04:30 4.50 COMPZN, CSGRCY TRIP P TOOH for clean out run // Inspect CIBP found 8ea 2"x2" slips lost in hole along with half of set ring 2,985.0 0.0 2/18/2025 04:30 2/18/2025 05:30 1.00 COMPZN, CSGRCY CLEN P Clean up floor // Empty stack and inspect for debris 0.0 0.0 2/18/2025 05:30 2/18/2025 07:30 2.00 COMPZN, CSGRCY BHAH P Bring in clean out assembly, strap and thaw // Pick up clean out BHA 6-1/8" junk mill w/ 6-1/8" string mill 0.0 100.0 2/18/2025 07:30 2/18/2025 09:30 2.00 COMPZN, CSGRCY TRIP P TIH w/ clean out BHA# 2 T/ 2,900' 100.0 2,900.0 Rig: NORDIC 3 RIG RELEASE DATE 2/24/2025 Page 3/7 2P-419 Report Printed: 3/19/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/18/2025 09:30 2/18/2025 10:15 0.75 COMPZN, CSGRCY REAM P Obtain parameters.// Pump 4 bbls/min @ 948 psi // Ream down T/ 3500' , initial debris encountered 2991' 2,900.0 3,500.0 2/18/2025 10:15 2/18/2025 11:30 1.25 COMPZN, CSGRCY CIRC P Circulate hole clean 3,500.0 3,500.0 2/18/2025 11:30 2/18/2025 13:30 2.00 COMPZN, CSGRCY SLPC P Slip and cut drill line 3,500.0 3,500.0 2/18/2025 13:30 2/18/2025 15:00 1.50 COMPZN, CSGRCY TRIP P TOOH for CIBP 3,500.0 150.0 2/18/2025 15:00 2/18/2025 16:00 1.00 COMPZN, CSGRCY BHAH P L/D BHA #2 (Dlean out assembly ) 150.0 0.0 2/18/2025 16:00 2/18/2025 18:00 2.00 COMPZN, CSGRCY TRIP P TIH w/ BHA #3 (CIBP setting tool) 0.0 3,345.0 2/18/2025 18:00 2/18/2025 18:30 0.50 COMPZN, CSGRCY MPSP P Set CIBP 58' below SC shoe. Top @ 3345'. Pressure up to 1800 psi to set. See 1st Shear. Cont. pressure up to 3700 psi. Press. up to 3800 psi to release. Sheared out 1K overpull. Released off CIBP. 3,345.0 3,345.0 2/18/2025 18:30 2/18/2025 20:00 1.50 COMPZN, CSGRCY TRIP P TOOH w/ BHA #3 (CIBP setting tool) 3,345.0 10.0 2/18/2025 20:00 2/18/2025 20:30 0.50 COMPZN, CSGRCY BHAH P L/D BHA #3 (CIBP setting tool) 10.0 0.0 2/18/2025 20:30 2/18/2025 21:00 0.50 COMPZN, CSGRCY PRTS P Test CIBP 1000 PSI / 10 miin 0.0 0.0 2/18/2025 21:00 2/18/2025 21:30 0.50 COMPZN, CSGRCY BHAH P MU BHA #4 (MSC) 0.0 11.8 2/18/2025 21:30 2/18/2025 23:00 1.50 COMPZN, CSGRCY TRIP P TIH w/ BHA #4 (MSC) to 3250', Std 36'. PUW = 70K. SOW = 60K. 11.8 3,250.0 2/18/2025 23:00 2/19/2025 00:00 1.00 COMPZN, CSGRCY CPBO P Obtain parameters. Free torque w/ pumps off = 2.2K. Bring pumps online. TIH slowly to locate collars. Locate collar @ 3292' & 3335'. Position MSC blades @ 3,340' (53' below SC shoe). Goto 100 RPM, 1 BPM @ 124 psi. See torque up to 3600 Lb/Ft. Work pump rate up to 2 BPM @ 775 PSI. Get torque spike to 4K. OA jumped to 400 PSI. Continue cutting working in hole 3,250.0 3,340.0 2/19/2025 00:00 2/19/2025 02:00 2.00 COMPZN, CSGRCY CIRC P Circulate deep clean pill down tubing out OA. When all of deep clean on backside go to pumping down DP X 7" annulas. @ 6 BPM, 145 BBls Shut down OWFF 3,340.0 3,340.0 2/19/2025 02:00 2/19/2025 05:00 3.00 COMPZN, CSGRCY CIRC P Observed well. OA sputtering. DP no flow. Line up. Perform second circulation. 2 BPM @ 725 PSI down DP, SD. bleed off tubing 30 PSI. Tubing at 0. OA will build slightly when shut in. Get top drive blown down 3,340.0 3,340.0 2/19/2025 05:00 2/19/2025 06:00 1.00 COMPZN, CSGRCY CIRC P OA not dead. Line up down kill. Pump 100 BBls 3,340.0 3,340.0 2/19/2025 06:00 2/19/2025 10:00 4.00 COMPZN, CSGRCY OWFF P Monitor well for ballooning, Pressure bleeding down from 130 psi to 0 in increments // Downward trend observed // NF@ 09:30 30 min no flow 3,340.0 3,340.0 2/19/2025 10:00 2/19/2025 12:00 2.00 COMPZN, CSGRCY TRIP P TOOH w/ MSC 3,340.0 0.0 2/19/2025 12:00 2/19/2025 12:30 0.50 COMPZN, CSGRCY CLEN P Clean and clear rig floor // Prep for pulling packoff 0.0 0.0 2/19/2025 12:30 2/19/2025 13:00 0.50 COMPZN, CSGRCY THGR P Pull packoff from 7" hanger 0.0 0.0 2/19/2025 13:00 2/19/2025 13:30 0.50 COMPZN, CSGRCY RURD P Rig up casing crew to pull 7" 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 2/24/2025 Page 4/7 2P-419 Report Printed: 3/19/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/19/2025 13:30 2/19/2025 15:30 2.00 COMPZN, CSGRCY THGR P Pick up landing jt // Make up to hanger // Pull hanger off seat150k pipe moved 4' then became stuck // Attempt to pull up to 410K no movement // pump 5 bpm @ 250 psi wile working pipe up to 410k no movement 0.0 0.0 2/19/2025 15:30 2/19/2025 16:00 0.50 COMPZN, CSGRCY RURD P Rig down casing equipment // Lay down landing joint 0.0 0.0 2/19/2025 16:00 2/19/2025 16:30 0.50 COMPZN, CSGRCY BHAH P M/U BHA #5. 7" MSC 0.0 11.8 2/19/2025 16:30 2/19/2025 19:00 2.50 COMPZN, CSGRCY TRIP P Trip in well. BHA #5 7" MSC 11.8 3,255.0 2/19/2025 19:00 2/19/2025 19:30 0.50 COMPZN, CSGRCY CPBO P KU, Parameters, 100RPM FT=2.2K, PUW=65K. SOW=59K, 1 BPM=133 PSI. RIH set down @ 3245', collar. Continue in to 3268. Cutter blades @ 3267. Rotate 100 RPM @ 2.2K Torque. 1 BPM @ 130 PSI. Work up to 2 BPM @ 556PSI. Tourque worked up to 4K then broke over 3,255.0 3,267.0 2/19/2025 19:30 2/19/2025 20:00 0.50 COMPZN, CSGRCY OWFF P Shut down rotary and pump. getting fluid out backside. 3,267.0 3,267.0 2/19/2025 20:00 2/19/2025 21:00 1.00 COMPZN, CSGRCY CIRC P Circulate BU @ 2BPM @ 520 PSI. 90 BBls pumped. OWFF 3,267.0 3,267.0 2/19/2025 21:00 2/19/2025 22:30 1.50 COMPZN, CSGRCY TRIP P TOOH, PUW=65K 3,267.0 11.0 2/19/2025 22:30 2/19/2025 23:00 0.50 COMPZN, CSGRCY BHAH P Lay down BHA #5 7" MSC 11.0 0.0 2/19/2025 23:00 2/20/2025 00:00 1.00 COMPZN, CSGRCY RURD P Rig up 7" elevators, P/U 7" landing joint, Screw into casing hanger. Work pipe to 410K multiple times. Set down on 7". 0.0 0.0 2/20/2025 00:00 2/20/2025 00:30 0.50 COMPZN, CSGRCY BHAH P M/U BHA #6, 7" MSC 0.0 11.8 2/20/2025 00:30 2/20/2025 02:00 1.50 COMPZN, CSGRCY TRIP P Trip in well, BHA #6, 7" MSC cutter 11.8 2,788.0 2/20/2025 02:00 2/20/2025 04:00 2.00 COMPZN, CSGRCY CPBO P KU, Obtain parameters, PUW=63K, RIW=59K 100 RPM,, FT=19.5, 1 BPM @ 130 PSI. PUH to 2725'. Locate collars @ 2733 & 2773. Make cut @ 2753'. 100 RPM. 2.4 BPM @ 697 PSI 2,788.0 2,753.0 2/20/2025 04:00 2/20/2025 04:30 0.50 COMPZN, CSGRCY OWFF P OWFF 2,753.0 2,753.0 2/20/2025 04:30 2/20/2025 06:00 1.50 COMPZN, CSGRCY TRIP P TOOH lay down cutter 2,753.0 0.0 2/20/2025 06:00 2/20/2025 07:00 1.00 COMPZN, CSGRCY THGR P Make up landing jt, pull hanger to floor 200k-250k 0.0 2,720.0 2/20/2025 07:00 2/20/2025 08:00 1.00 COMPZN, CSGRCY CIRC P Circulate well, 3.5 bpm @ 140 psi // Large amount of sand unload on bottoms up 2,720.0 2,720.0 2/20/2025 08:00 2/20/2025 10:45 2.75 COMPZN, CSGRCY PULL P Pull and lay down 65 jts 7" BTC casing, 22.94' Cut jt, 42 centering guides 2,720.0 0.0 2/20/2025 10:45 2/20/2025 11:45 1.00 COMPZN, CSGRCY CLEN P Clean and clear rig floor for picking up BHA 0.0 0.0 2/20/2025 11:45 2/20/2025 12:15 0.50 COMPZN, CSGRCY SFTY P Safety stand down for incident discussion on camps 0.0 0.0 2/20/2025 12:15 2/20/2025 13:45 1.50 COMPZN, CSGRCY BHAH P Pick up fishing BHA 7" spear 0.0 250.0 2/20/2025 13:45 2/20/2025 14:45 1.00 COMPZN, CSGRCY TRIP P TIH to top of fish @ 2753' 250.0 2,753.0 2/20/2025 14:45 2/20/2025 18:30 3.75 COMPZN, CSGRCY JAR P Engage fish T/ 2761' , Jar 200K over 62 times straight pull to 400K 2,753.0 2,761.0 2/20/2025 18:30 2/20/2025 19:30 1.00 COMPZN, CSGRCY SVRG P Crew change, Post jarring derrick and top drive inspection 2,761.0 2,761.0 Rig: NORDIC 3 RIG RELEASE DATE 2/24/2025 Page 5/7 2P-419 Report Printed: 3/19/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/20/2025 19:30 2/20/2025 20:00 0.50 COMPZN, CSGRCY JAR P Continue jarring on stuck 7" surface casing, 200K over straight pull to 410K. 10 cycles. Fish came free. Dragging up @ 275-300K 2,761.0 2,761.0 2/20/2025 20:00 2/20/2025 21:00 1.00 COMPZN, CSGRCY CIRC P Circulate BU @ 4 BPM 345PSI. OWFF 2,761.0 2,700.0 2/20/2025 21:00 2/20/2025 23:30 2.50 COMPZN, CSGRCY TRIP P Trip out of well, PUW=98K. 5 - 10K drag. Swabbing pulling slow 2,700.0 228.0 2/20/2025 23:30 2/21/2025 00:00 0.50 COMPZN, CSGRCY BHAH P At BHA. start laying down 228.0 140.0 2/21/2025 00:00 2/21/2025 01:00 1.00 COMPZN, CSGRCY BHAH P Continue to lay down BHA #7. Release spear from fish 140.0 0.0 2/21/2025 01:00 2/21/2025 02:00 1.00 COMPZN, CSGRCY PULL P Lay down 7" surface casing from cut @ 3267', 11 full joints, 1, 17.5' & 24.0 cut joints. No centralizers 514.0 0.0 2/21/2025 02:00 2/21/2025 03:30 1.50 COMPZN, CSGRCY BHAH P M/U BHA #8, Fishing string with spear pack off. 0.0 230.0 2/21/2025 03:30 2/21/2025 05:30 2.00 COMPZN, CSGRCY TRIP P Trip in BHA #8 on DP 230.0 3,260.0 2/21/2025 05:30 2/21/2025 06:00 0.50 COMPZN, CSGRCY FISH P Engage fish No-go @ 3267', Jar on fish 1 time 150 over, fish free 3,260.0 3,245.0 2/21/2025 06:00 2/21/2025 06:30 0.50 COMPZN, CSGRCY CIRC P Circulate B/U 3,245.0 3,245.0 2/21/2025 06:30 2/21/2025 08:45 2.25 COMPZN, CSGRCY TRIP P Trip out of hole with fish 3,245.0 300.0 2/21/2025 08:45 2/21/2025 10:15 1.50 COMPZN, CSGRCY BHAH P Lay down fishing BHA and fish 300.0 0.0 2/21/2025 10:15 2/21/2025 11:15 1.00 COMPZN, CSGRCY CLEN P Clean and clear rig floor 0.0 0.0 2/21/2025 11:15 2/21/2025 12:15 1.00 COMPZN, CSGRCY RURD P Rig up to run 4.5" tubing 0.0 0.0 2/21/2025 12:15 2/21/2025 13:30 1.25 COMPZN, CSGRCY PUTB P Pick up and run 4.5" tubing T/ 1993' 0.0 1,993.0 2/21/2025 13:30 2/21/2025 16:30 3.00 COMPZN, CSGRCY RGRP T Replace supply hose on tubing tongs 1,993.0 1,993.0 2/21/2025 16:30 2/21/2025 17:00 0.50 COMPZN, CSGRCY SVRG P Re-commission hose on tongs 1,993.0 1,993.0 2/21/2025 17:00 2/21/2025 20:15 3.25 COMPZN, CSGRCY PUTB P Crew change out. RIH w/ 4 1/2" cement string T/ 3283'. PUW=xxK, SOW=xxK. 1,222.0 3,283.0 2/21/2025 20:15 2/21/2025 22:00 1.75 COMPZN, CSGRCY WASH P Wash in hole F/ 3283' T/ 3035' @ 4 BPM,50 PSI. M/U 12' space out pups. Run last full joint # 108 T/ 3326'. Cross over T/ 3 1/2" IF. M/U 9.95' IF pup joint. Park bottom of cement string @ 3335' 3,283.0 3,335.0 2/21/2025 22:00 2/21/2025 22:30 0.50 COMPZN, CSGRCY RURD P B/D TD. R/U HES & cement line. Blow air to cementers. Batch up spacer. 3,335.0 3,335.0 2/21/2025 22:30 2/21/2025 23:00 0.50 COMPZN, CSGRCY SFTY P PJSM w/ HES & rig crew on pumping balance cement plug. 3,335.0 3,335.0 2/21/2025 23:00 2/21/2025 23:15 0.25 COMPZN, CSGRCY PRTS P HES flood lines w/ 5 Bbls brine. PT cement line T/ 3350 PSI. Start job @ 23:04 Hrs. 3,335.0 3,335.0 2/21/2025 23:15 2/22/2025 00:00 0.75 COMPZN, CSGRCY CMNT P Batch up cement. Cement wet @ 23:20 Hrs. 3,335.0 3,335.0 Rig: NORDIC 3 RIG RELEASE DATE 2/24/2025 Page 6/7 2P-419 Report Printed: 3/19/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/22/2025 00:00 2/22/2025 01:00 1.00 COMPZN, CSGRCY CMNT P Pump 22 Bbls 10 PPG spacer w/ Surf wash @ 2.3 BPM, 80 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 39 Bbls 15.8 PPG PTA cement w/ 5 lbs/bbls Bridge Maker II LCM @ 2.3 BPM, 235 PSI. Close UPR. Drop 5" foam ball. Open UPR. Pump 6 Bbls 10 PPG spacer @ 2.3 BPM, 65 PSI. Displace w/ 34.7 Bbls 9.8 PPG brine @ 3.5 BPM, 250 PSI. Good returns throughout job. End job @ 00:49 Hrs. 3,335.0 3,335.0 2/22/2025 01:00 2/22/2025 01:15 0.25 COMPZN, CSGRCY RURD P B/D cement line. R/D cement line. L/D 3 1/2" IF pup p & head pin. 3,335.0 3,325.0 2/22/2025 01:15 2/22/2025 03:30 2.25 COMPZN, CSGRCY PULL P POOH @ 20 FPM, Rotate @ 5 RPM, 1.2K Tq T/ 2760'. PUW=63K 3,325.0 2,760.0 2/22/2025 03:30 2/22/2025 04:00 0.50 COMPZN, CSGRCY PULL P POOH @ 20 FPM T/ 2541'. PUW=55K. Cement in place @ 04:00 2,760.0 2,541.0 2/22/2025 04:00 2/22/2025 04:45 0.75 COMPZN, CSGRCY CIRC P Circ STS @ 8 BPM, 120 PSI. Overboard contaminated fluid. 2,541.0 2,541.0 2/22/2025 04:45 2/23/2025 00:00 19.25 COMPZN, CSGRCY WOC P Wait on cement to reach 500 PSI compressive strength. State witness notification sent for 04:30 Hrs tomorrow. 2,541.0 2,541.0 2/23/2025 00:00 2/23/2025 12:00 12.00 COMPZN, CSGRCY WOC P Wait on cement to reach 500 PSI compressive strength. State witness notification sent for 04:30 Hrs tomorrow. Wait on cement sample to harden up. 2,541.0 2,541.0 2/23/2025 12:00 2/23/2025 13:00 1.00 COMPZN, CSGRCY WASH P Wash in hole on singles to top of cement @ 2662' // Set down 10K WOB 2,541.0 2,662.0 2/23/2025 13:00 2/23/2025 14:00 1.00 COMPZN, CSGRCY CIRC P Circulate SxS @ 6 bpm 151 psi // Kick green cement to cuttings tank 2,662.0 2,650.0 2/23/2025 14:00 2/23/2025 15:30 1.50 COMPZN, CSGRCY PRTS P Pressure test cement 1500 psi // 330 psi leak off over 30 min Failed test 2,650.0 2,650.0 2/23/2025 15:30 2/23/2025 17:30 2.00 COMPZN, CSGRCY TRIP P TOOH for Mule shoe 2,650.0 0.0 2/23/2025 17:30 2/23/2025 18:00 0.50 COMPZN, CSGRCY SFTY P Crew change out. 0.0 0.0 2/23/2025 18:00 2/23/2025 18:15 0.25 COMPZN, CSGRCY RURD P Change out handling equipment T/ DP. 0.0 0.0 2/23/2025 18:15 2/23/2025 18:45 0.50 COMPZN, CSGRCY WWWH P Jet BOP stack. 0.0 0.0 2/23/2025 18:45 2/23/2025 19:00 0.25 COMPZN, CSGRCY RURD P Change out handling equipment T/ TBG 0.0 0.0 2/23/2025 19:00 2/23/2025 20:15 1.25 COMPZN, CSGRCY PUTB P M/U 4 1/2", 12.6#, L-80, NSCT mule shoe. RIH out of derrick T/ 2422'. PUW=55K. SOW=50K. 0.0 2,422.0 2/23/2025 20:15 2/23/2025 20:30 0.25 COMPZN, CSGRCY PULD P L/D stand of 4 1/2" TBG out of derrick. 2,422.0 2,422.0 2/23/2025 20:30 2/23/2025 21:30 1.00 COMPZN, CSGRCY HOSO P M/U 4 1/2" Hanger & landing joint. Suck out stack. RIH land hanger w/ bottom of mule shoe @ 2448'. RILDS. L/D landing joint. 2,422.0 2,448.0 2/23/2025 21:30 2/23/2025 21:45 0.25 COMPZN, CSGRCY MPSP P Set HP BPV. 2,448.0 2,448.0 2/23/2025 21:45 2/23/2025 22:15 0.50 COMPZN, CSGRCY RURD P R/U testing equipment. 2,448.0 2,448.0 2/23/2025 22:15 2/23/2025 22:30 0.25 COMPZN, CSGRCY PRTS P PT BPV from below. 1000 PSI rolling test for 10 Min. 2,448.0 0.0 2/23/2025 22:30 2/23/2025 22:45 0.25 COMPZN, WHDBOP RURD P B/D, R/D testing equipment. 0.0 2/23/2025 22:45 2/24/2025 00:00 1.25 COMPZN, WHDBOP NUND P Pull flow riser, R/D trip tank hose. N/D BOP. Rack back on stump. Install tree test dart. Rig: NORDIC 3 RIG RELEASE DATE 2/24/2025 Page 7/7 2P-419 Report Printed: 3/19/2025 Operations Summary (with Timelog Depths) Job: RECOMPLETION Time Log Start Time End Time Dur (hr) Phase Activity Code Time P-T-X Operation Start Depth (ftKB) End Depth (ftKB) 2/24/2025 00:00 2/24/2025 01:15 1.25 COMPZN, WHDBOP NUND P N/U old adaptor spool & tree. 0.0 0.0 2/24/2025 01:15 2/24/2025 01:30 0.25 DEMOB, MOVE PRTS P PT hanger void T/ 5000 PSI for 10 Min. 0.0 0.0 2/24/2025 01:30 2/24/2025 02:30 1.00 DEMOB, MOVE RURD P R/U circ equipment & LRS. 0.0 0.0 2/24/2025 02:30 2/24/2025 02:45 0.25 DEMOB, MOVE SFTY P PJSM w/ LRS & rig crew on test & freeze protect. 0.0 0.0 2/24/2025 02:45 2/24/2025 03:45 1.00 DEMOB, MOVE PRTS P PT tree T/ 5000 PSI for 5 Min. 0.0 0.0 2/24/2025 03:45 2/24/2025 04:15 0.50 DEMOB, MOVE MPSP P Pull test dart & BPV. 0.0 0.0 2/24/2025 04:15 2/24/2025 05:30 1.25 DEMOB, MOVE FRZP P LRS pump 36 Bbls diesel down IA. Taking returns out TBG T/ tiger tank. ICP=500, FCP=575 Release LRS. U-tube well for 1 Hr. 0.0 0.0 2/24/2025 05:30 2/24/2025 06:00 0.50 DEMOB, MOVE RURD P Complete rig down of cellar, Rig Released 06:00 0.0 0.0 Rig: NORDIC 3 RIG RELEASE DATE 2/24/2025 DTTMSTART JOBTYP SUMMARYOPS 3/20/2024 ACQUIRE DATA (SECURE) BLEED IA TO 0 PSI POST DDT T (COMPLETE). 3/23/2024 CHANGE WELL TYPE TUBING PUNCH DEPTH=9800'-9803', CCL-TS=3.9', CCL STOP DEPTH=9796.1', LOG CORRELATED TO TUBING TALLY DATED 2/08/2004. LRS BEGAN CIRC TEST ON WELL, ABLE TO PUMP 5 BBLS @ 1 BPM WITH T/I PRESSURES=500/260 & 80 PSI DOWNSTREAM OF CHOKE, AFTER 5 BBLS T/I PRESSURES=800/400 & 130 PSI DOWNSTREAM OF CHOKEI & RISING, HAD TO SHUT DOWN PUMP DUE TO DOWNSTREAM PRESSURE LIMITS, PLAN TO RECONFIGURE DOWNSTREAM GAUGE LOCATION IN THE MORNING & CONTINUE CIRC TEST, WELL LEFT S/I, FUSIBLE REMOVED & DSO NOTIFIED. 3/25/2024 CHANGE WELL TYPE RIG UP LRS EQUIPMENT TO TBG, PUMP 15 BBLS DOWN TBG @ 2BPM, 1000 PSI PUMP PRESSURE THROUGH PERFERATIONS AND UP IA TO TANK, U TUBE, JOB COMPLETE, RIG DOWN 3/26/2024 ACQUIRE DATA (SECURE) BLEED OA FOR BUR (COMPLETE) 3/27/2024 CHANGE WELL TYPE COMPLETE BALANCE PLUG ,PUMPED 50 BBL CHEM WASH, 370 BBL 9.8 NaCl FOLLOWED BY 51 BBL 15.8 PPG CEMENT @ 2BPM 251 PSI, DISPLACED WITH 116 BBL 9.8 NaCl WITH A 2BBL DIESEL SURFACE. 3/29/2024 CHANGE WELL TYPE SHOOT TUBING PUNCHER FROM 2007' - 2010', CIRCULATE 90 BBLS OF DIESEL DOWN TUBING UP IA AT 2.0 BPM @ 100 PSI. VERIFIED DIESEL AT TANK. READY FOR SW TAG & TEST. 3/30/2024 CHANGE WELL TYPE **STATE WITNESS** TAG TOP OF CEMENT @ 7889' RKB (KAM ST JOHN), PERFORM PASSING CMIT TO 1718 PSI. JOB COMPLETE. WELL READY FOR E-LINE. 3/31/2024 CHANGE WELL TYPE CUT 4.5" TUBING WITH WELLTEC MECHANICAL CUTTER AT 3685' RKB. TATTLETALE SHOWED BLADE EXTENSION TO 4.77" AND CCL SHIFT SEEN ON LOG AFTER CUTTING (TBG WAS IN TENSION). JOB COMPLETE, READY FOR RIG 2/16/2025 RECOMPLETION Warm up moving system hydraulics. Prep rig to back off well. Back off 2P-422A. Stage rig. Clean up pad. Kick out old tree. Lay pit liner and T-mats. Pull sub over well 2P-419. Shim & berm in rig. Unable to level rig over well. Pull off well. Reshoot pad. Roads and pads leveled pad. Pull sub over well. MIRU. Spot auxiliary equipment. Gather initial RKB's and pressures. Complete rig acceptance check list. Accept rig @ 04:00. Take on 9.8# NaCl to pits. RU and PT hardline, Displace well to 9.8# NaCl 285 bbls, shut down observe well for flow, IA still flowing, rig up and circulate 125 bbls 9.8 brine 2/17/2025 RECOMPLETION OWFF. Set BPV + test dart. ND old tree and hang. Inspect hanger neck threads. NU BOP. RU testing equipment. Fill stack. Shell test BOP. Perform initial BOP test to 250/2500 psi (witness waived by Adam Earl). Pull BPV. MU landing joint. Screw in TD. Set 10K down. BOLDS. Pull hanger to rig floor. Unseat hanger @ 70K. Drag to floor @ 65K. Circ BU. OWFF. L/D landing joint, hanger, pups. Pull 4 1/2" Tubing F/ pre-rig cut @ 3,685'. Cut Joint = 143' long. MU BHA #1 (7" CIBP). TIH w/ CIBP, Stack out @ 2,985', unable to pass, flow check for trip out of hole for cleanout run 2/18/2025 RECOMPLETION TOOH for clean out BHA ,Inspect CIBP found 8ea 2"x2" slips lost in hole along with half of set ring, Clean up floor // Empty stack and inspect for debris Bring in clean out assembly, strap and thaw // Pick up clean out BHA 6-1/8" junk mill w/ 6-1/8" string mill,TIH w/ clean out BHA# 2 T/ 2,900', Obtain parameters.// Pump 4 bbls/min @ 948 psi // Ream down T/ 3500' , initial debris encountered 2991', TOOH. M/U BHA #3 CIBP. TIH. Set @ 3345'. POOH. M/U MSC. TIH. KU 3250. Locate collars @ 3292 & 3335. Make 7" cut @ 3340. Obsewrve OA go from 60 PSI to 400 PSI 2/19/2025 RECOMPLETION Circulate deep clean pill down tubing up OA. OWFF. OA not dead. Tubing side is. OA not dead. Line up down kill. Pump 100 BBls. Monitor well, Pressure bleeding down from 130 psi to 0 in increments // Downward trend observed // NF@ 09:30 30 min no flow. Trip out of hole. M/U Landing joint. PU on 7" casing. Unable to pull 7" free. M/U MSC. TIH. Obtain parameters. Locate collar @ 3245. Make cut @ 3267. Slight flow from flow. Circ BU. OWFF. TOOH. M/U 7" landing joint. Pull on 7" casing. Not free 2/20/2025 RECOMPLETION Unable to pull 7" casing. RIH BHA #7 MSC. Cut 7" at 2753. TOOH. Able to pull 7" casing from cut @ 2753'. M/U BHA #8 Fishing package with drill collars. Latch fist @ 2753. Fully engaged @ 2762. Jar fish 72 cycles. Pull free. Pull 7" casing 2753 to cut @ 3267 2P-419 Rig Suspend Summary of Operations 2/21/2025 RECOMPLETION Cont L/D BHA #7 & 5 1/2" CSG fish. 11 full joints, 1, 17.5' & 24.0 cut joints. M/U BHA #8, spear w/ no pack off. RIH Engage fish No-go @ 3267', Jar on fish 1 time 150 over, fish free. Circ BU. POOH, L/D BHA #8 & 5 1/2" CSG fish. Change handling equipment. Run 4 1/2" cement string T/ 1993'. Rig repair replace hydraulic supply hose on tubing tongs. Cont RIH w/ 4 1/2" cement string T/ 3283'. Wash in hole @ 4 BPM T/ 3335'. Rig HES cement unit & cement hose. Batch up spacer. Flood lines & PT cement lines. Batch up cement. Cement wet @ 23:20 Hrs. Begin pumping surface shoe balance plug. 2/22/2025 RECOMPLETION Complete pumping surface shoe balance plug. L/D space out pups. POOH @ 20 FPM, Rotating @ 5 RPM T/ 2544'. Circ STS @ 8 BPM, over boarding contaminated fluid. WOC to reach 500 PSI compressive strength. State witness notification sent for 04:30 Hrs tomorrow 2/23/2025 RECOMPLETION WOC sample to harden up. Wash in hole @ 4 BPM. Tag cement top w/ 10K SOW. Circ out green cement @ 6-8 BPM. L/D single. rig up test equipment, PT Cement 1500 psi 30 min AOGCC witnessed Kam StJohn, test failed 330 psi leak off over 30 min, TOOH for mule shoe. Jet BOP stack. RIH w/ 4 1/2" kill string w/ mule shoe. M/U hanger & landing joint. Land hanger bottom of mule shoe @ 2448'. RILDS. Set HP BPV. PT BPV from below for 10 Min. N/D BOP, Install tree test dart. 2/24/2025 RECOMPLETION N/U old adaptor spool & tree. PT hanger void T/ 5000 PSI for 10 Min. R/U LRS and circ manifold. PT tree T/ 5000 PSI for 5 Min. Pull test dart & BPV. LRS pump 36 Bbls diesel freeze protect down OA. U- tube well for 1 Hr. Secure tree and cellar. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10945'None Casing Collapse Structural Conductor Surface Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng (907) 263-4131 Staff Well Interventions Engineer KRU 2P-419 5671' 10199' 5332' 2609 2662', 3345', 7889', 10199' N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: Jill.Simek@conocophillips.com AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 9893' MD and 5202' TVD 9909' MD and 5210' TVD N/A Jill Simek STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 204-017 P.O. Box 100360, Anchorage, AK 99510 50-103-20483-00 Kuparuk River Field Meltwater Oil Pool-Suspended ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned TVD Burst 9946' MD 108' 2352' 108' 3287' 5276'10065' 16" 9-5/8" 79' 3259' 10216-10236', 10250-10290', 10510-10570', 10644-10664' 10040' 3-1/2" 5339-5348', 5354-5371', 5467- 5493', 5527-5537' 7" Perforation Depth TVD (ft): 6/15/2025 10943'1050' 4-1/2" 5670' Packer: Baker ZXP Liner Top Packer Packer: Baker 80-40 GHB-22 Seal Assy SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 4:10 pm, May 13, 2025 Jill Simek Digitally signed by Jill Simek Date: 2025.05.13 15:51:03 -08'00' 325-300 X --00 SFD X A variance is approved for the placement of a BISN plug under 25 AAC 25.112(i) with the following conditions: The BISN state witnessed plug tag and pressure test and 1 hour draw down test are required. A 24 hour draw down test is required with the results submitted to the AOGCC. A cement plug from the top of BISN plug to surface is required. DSR-6/3/25 December 31, 2025 SFD 6/13/2025 10-407 X Abandonment must be complete by 12/31/2025. VTL 6/23/2025*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date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rom:Loepp, Victoria T (OGC) To:Loepp, Victoria T (OGC) Subject:FW: [EXTERNAL]: KRU 2P-419 & 2P-429 Abandonment Sundries Date:Monday, June 23, 2025 12:27:12 PM -----Original Message----- From: Livingston, Erica J <Erica.J.Livingston@conocophillips.com> Sent: Monday, June 23, 2025 11:35 AM To: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Simek, Jill <Jill.Simek@conocophillips.com>; Bronga, Jaime <Jaime.Bronga@conocophillips.com>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com>; Kolstad, Scott <Scott.Kolstad@conocophillips.com> Subject: RE: [EXTERNAL]: KRU 2P-419 & 2P-429 Abandonment Sundries Victoria, CPAI's proposal is to perform the following after placing the BiSN plug: - an AOGCC-witnessed tag per regulation - an AOGCC-witnessed pressure test per regulation - an AOGCC-witnessed 1-hour draw down test (DDT) - 24-hour DDT with the results submitted to the AOGCC Thank you for the consideration of this variance, E Erica Livingston Intervention & Integrity Supervisor, P.E. | ConocoPhillips Alaska +1 907 854 6886 (cell) ekappel@conocophillips.com -----Original Message----- From: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Sent: Monday, June 16, 2025 3:32 PM To: Livingston, Erica J <Erica.J.Livingston@conocophillips.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; Hobbs, Greg S <Greg.S.Hobbs@conocophillips.com>; Simek, Jill <Jill.Simek@conocophillips.com>; Bronga, Jaime <Jaime.Bronga@conocophillips.com>; Zwarich, Nola R <Nola.R.Zwarich@conocophillips.com>; Kolstad, Scott <Scott.Kolstad@conocophillips.com>; Livingston, Erica J <Erica.J.Livingston@conocophillips.com> Subject: Re: [EXTERNAL]: KRU 2P-419 & 2P-429 Abandonment Sundries Please outline your proposal for PT and tag, drawdown test of the plugs. Sent from my iPhone > On Jun 16, 2025, at 3:08ௗPM, Livingston, Erica J <Erica.J.Livingston@conocophillips.com> wrote: > > CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. > Victoria, et al, > > Jill Simek is on vacation, so this e-mail is coming from me in her absence. > > Attached is the requested documentation that shows BiSN alloy plugs are as effective as cement in P&A applications. > > This technology is one that has been used and accepted by regulators around the world (see regions below). > [cid:image001.png@01DBDEC5.725888D0] > > > 1. The first attachment is the latest presentation that bisn gave to BSEE earlier this year. Slide 11 shows worldwide deployments through end of 2024. Slides 12-15 show more detail on U.S. BSEE deployments from Jul 2022 through Dec 2024. Summation of jobs to date shown in the screen shot above. > > > 1. The second attachment is a May 2022 SPE paper co-authored by Aker BP that details the success of bisn plugs in a 30 well P&A campaign in the Valhall field offshore Norway. This paper also documents the 2-year field verification that was successfully completed ahead of this campaign (see pages 10-11). An updated version of Figure 14 (page 15) is copied below and shows that these 30 wells with bisn plugs have not shown any signs of leaking since the 2021 campaign execution. > > [cid:image002.png@01DBDEC5.725888D0] > > > 1. The third attachment (bismuth-based-barrier-materials…) is third party testing that was conducted to benchmark the performance of bismuth alloy plugs against conventional cement. The results clearly demonstrate the superior mechanical sealing capability of bismuth alloys. > > * Slide 13 presents data confirming that bismuth alloy plugs exhibit significantly higher resistance to axial loads compared to cement, indicating better structural integrity under compressive forces. > * Slide 16 shows results from hydraulic push-out testing, where bismuth alloy plugs demonstrated significantly greater strength than cement. > * Slide 19 highlights bismuth alloy's superior resistance to gas migration, a critical factor for long-term well integrity and P&A. > Collectively, these tests validate that bismuth alloys outperform cement in key mechanical and sealing performance criteria. Slide 22 refers to future testing intended to further evaluate plug performance relative to plug length, casing size, and other variables to optimize design and deployment. > > > 1. The fourth attachment (Qualification of Bismuth Alloy Plugs for Plug & Abandonment (PDF) from January 2023 documents the qualification of BiSN alloy plugs for P&A applications in the North Sea UK adhering to the OGUK Guidelines for Qualification of Materials for Abandonment of Wells, Issue 2 of 2015. > > > 1. The fifth attachment (PD4977 Information – 2 May 2025) is a summary of Alaska deployments as well as a tool sequence depiction for the proposed 2P-419 and 2P-429 jobs. There is a slide summarizing global deployments as well. > > > > 1. The sixth attachment (PD4977 – BiSN Design Factor – V1) is the 2P-419 and 2P-429 Design Factor calculations for the proposed BiSN plugs. The BiSN plug barrier pressure rating is estimated to be 3,685 psi. > > Please reach out with any questions on the provided material. > > > Additionally, there was a request to place 25 ft of cement on top of the BiSN plug. > > In the sundry requests submitted, the plan is to place a cement plug from the top of the BiSN plug to surface (~2062 ft TVD in 2P-419 and ~2204 ft TVD in 2P-429). > I believe we incorrectly showed a gap above the BiSN plug in the sundry’s schematics (see below). Cement pumped down the kill string would displace lighter weight fluid above the BiSN plug effectively filling the entire wellbore above the BiSN plug with cement for the surface plug. > [cid:image003.png@01DBDEC8.4F825A90] > [cid:image004.png@01DBDEC8.4F825A90] > > Please advise if this is sufficient to meet the intent of the 25 ft cement plug requested. > > Thank you for the consideration of this variance, E > > Erica Livingston > Intervention & Integrity Supervisor, P.E. | ConocoPhillips Alaska > +1 907 854 6886 (cell) > ekappel@conocophillips.com<mailto:ekappel@conocophillips.com> > > From: Loepp, Victoria T (OGC) > Sent: Wednesday, June 11, 2025 10:20 AM > To: Simek, Jill > <jill.simek@conocophillips.com<mailto:jill.simek@conocophillips.com>> > Cc: Rixse, Melvin G (OGC) > <melvin.rixse@alaska.gov<mailto:melvin.rixse@alaska.gov>>; Lau, Jack J > (OGC) <jack.lau@alaska.gov<mailto:jack.lau@alaska.gov>>; McLellan, > Bryan J (OGC) > <bryan.mclellan@alaska.gov<mailto:bryan.mclellan@alaska.gov>>; Boman, > Wade C (OGC) <wade.boman@alaska.gov<mailto:wade.boman@alaska.gov>> > Subject: KRU 2P-419 & 2P-429 Abandonment Sundries > > > Jill, > > The use of BISN beads does not meet the well plugging requirements of 20 AAC 25.112. However, a variance may be granted to the requirements if the variance provides for at least an equally effective plugging of the well 20 AAC 25.112(i). Please provide justification supporting a variance request for the use of the BISN beads. Include in your variance request the placement of 25’ of cement on top of the BISN beads. > > Victoria > > Victoria Loepp > Senior Petroleum Engineer > Alaska Oil & Gas Conservation Commission > Work: (907)793-1247 > > > MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 17 Township: 8N Range: 7E Meridian: Umiat Drilling Rig: Nordic 3 Rig Elevation: Total Depth: 10945 ft MD Lease No.: ADL 0373112 Operator Rep: Suspend: P&A: X Conductor: 16" O.D. Shoe@ 108 Feet Csg Cut@ Feet Surface: 9-5/8" O.D. Shoe@ 3287 Feet Csg Cut@ Feet Intermediate: O.D. Shoe@ Feet Csg Cut@ Feet Production: 7" O.D. Shoe@ 10065 Feet Csg Cut@ 3340 Feet Liner: 3-1/2" O.D. Shoe@ 10943 Feet Csg Cut@ Feet Tubing: 4-1/2" O.D. Tail@ 9946 Feet Tbg Cut@ 3685 Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Open Hole Bridge plug 3345 ft 2662 ft 9.8 ppg Drillpipe tag Initial 15 min 30 min 45 min Result Tubing IA 1740 1540 OA 0 0 Initial 15 min 30 min 45 min Result Test 2 Tubing IA 1770 1590 1440 OA 0 0 0 Remarks: Attachments: Chase Erdman F Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Tag was high but solid with 10K lbs down weight. Pumped 1.0 bbls in and 0 .9 bbls out. MIT failed - excess pressure loss February 23, 2025 Kam StJohn Well Bore Plug & Abandonment KRU 2P-419 ConocoPhillips Alaska Inc. PTD 2040170; Sundry 324-710 none Test Data: F Casing Removal: rev. 3-24-2022 2025-0223_Plug_Verification_KRU_2P-419_ksj 9 9 9 9 9 999 9 9 9 9 9 9 9 9 9 99 9 999 9 99 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.03.25 16:02:35 -08'00' Operations shutdownRepair WellFracture StimulatePlug PerforationsAbandon1. Type of Request: Change Approved ProgramPull TubingOther StimulatePerforateSuspend Other: ___________________Alter CasingPerforate New Pool Re-enter Susp WellPlug for Redrill 5.Permit to Drill Number:4. Current Well Class:2. Operator Name: DevelopmentExploratory 3. Address:ServiceStratigraphic 6. API Number: 8. Well Name and Number:7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? NoYes 10. Field:9.Property Designation (Lease Number): 11. Junk (MD):Effective Depth TVD:Effective Depth MD:Total Depth TVD (ft):Total Depth MD (ft): None10945' CollapseCasing Structural Conductor Surface Intermediate Production Liner Packers and SSSV MD (ft) and TVD (ft):Packers and SSSV Type: 13. W ell Class after proposed work:12. Attachments: Proposal Summary Wellbore schematic ServiceDevelopmentExploratory StratigraphicDetailed Operations Program BOP Sketch 15. W ell Status after proposed work:14. Estimated Date for WDSPLOIL WINJCommencing Operations:Suspended SPLUGGSTORWAGGASDate:16. Verbal Approval: AOGCC Representative: GINJ AbandonedOp Shutdown Contact Name: Contact Email: Contact Phone: Authorized Title: Sundry Number:Conditions of approval: Notify AOGCC so that a representative may witness Location ClearancePlug Integrity BOP Test Mechanical Integrity Test Other Conditions of Approval: Post Initial Injection MIT Req'd? NoYes APPROVED BY Date:THE AOGCCCOMMISSIONERApproved by: Sr Res EngSr Pet GeoSr Pet EngComm.Comm. 10943'1050' 4-1/2" 5670' Packer: Baker ZXP Liner Top Packer Packer: Baker 80-40 GHB-22 Seal Assy SSSV: None Perforation Depth MD (ft): L-80 3259' 10216-10236', 10250-10290', 10510-10570', 10644-10664' 10040' 3-1/2" 5339-5348', 5354-5371', 5467- 5493', 5527-5537' 7" Perforation Depth TVD (ft): 108' 3287' 5276'10065' 16" 9-5/8" 79' 9946' MD 108' 2352' ConocoPhillips Alaska, Inc. SizeLength Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool - Abandoned BurstTVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 204-017 P.O. Box 100360, Anchorage, AK 99510 50-103-20483-00 Kuparuk River Field Meltwater Oil Pool-Suspended AOGCC USE ONLY Tubing MD (ft):Tubing Grade: 9893' MD and 5202' TVD 9909' MD and 5210' TVD N/A Shane Germann Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: Shane.Germann@conocophillips.com (907) 263-4597 Senior RWO/CTD Engineer KRU 2P-419 7889', 10199'5332'10199'5671' N/A Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 1/19/2025 MPSP (psi): 783 Digitally signed by Shane Germann DN: O=ConocoPhillips, CN=Shane Germann , E=shane.germann@conocophillips.com Reason: I am the author of this document Location: Date: 2024.12.18 14:06:41-09'00' Foxit PDF Editor Version: 13.0.0 324-710 By Grace Christianson at 8:15 am, Dec 19, 2024 -00 SFD June 30, 2025 10-407 SFD 12/26/2024 X DSR-12/20/24 X BOP test to 2500 psig Annular preventer test to 2500 psig See attached "Conditions of Approval" X X VTL 12/27/2024 MEUIRUMEUIRUMOF 01/03/25Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.01.03 07:43:19 -09'00' RBDMS JSB 010925 KRU 2P-4ϭϵ Abandonment Conditions of Approval: ͳǤ A variance is granted from 20 AAC 25.112(a)(1)(A) which requires a cement plug from 100' below the base of the hydrocarbon-bearing strata. ʹǤ A variance is granted under 20 AAC 25.112(i) to allow the alternate plug placement described as the recovery of 50' of production casing below the surface casing shoe and a cement plug placed across this open hole section and 150' into the surface casing. The plug must pass a State Witnessed pressure test and tag according to 20 AAC 25.112(g). ͵Ǥ A variance to Order 196 is granted that will eliminate the requirement of logging the cement placed across the hydrocarbon-bearing strata. ͶǤ A failed pressure test of the surface casing shoe plug requires the submission of a new sundry (10-403) to cover the rigless abandonment scope if planned. Completion of workover operations under the original sundry will be complete and a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within 30 days following the completion of workover operations. ͷǤ If surface abandonment operations are not initiated within 0 days after the successful placement of the surface casing shoe plug (State witnessed pressure test and tag), a 10-407 Well Completion or Recompletion Report and Log must be filed with the Commission within30 days after the completion of workover operations to date. Ǥ Plugging of the surface of a well must meet the requirements of 20 AAC 25.112(d) and 20 AAC 25.120. Ǥ AOGCC witness is required after the wellhead cutoff and prior to a top job. Variances granted provide for at least equally effective plugging of the well and prevention of fluid movement into sources of hydrocarbons or freshwater. 2P-419 Plug and Abandonment Background & Objective 2P-419 was an injector that has been shut in since March 2021. This well is in progress of being suspended with a CIBP and cement (as of 3/7/2024). The steps to P&A this well include three more cement plugs: an intermediate plug across the tubing, a plug across the surface casing shoe after the tubing and production casing has been pulled, and then a final plug to surface. Well Data Meltwater Formation: x Reservoir pressure 7/31/2023 = 2912 PSI @ 4944’ TVD x MASP = 2609 psi C-80 Formation: x OAP = 199 psi (11/5/2022) (fluid packed with diesel) x MASP = 783 psi (0.1 PSI/FT gradient) Last MITIA 8/16/2022 to 3590 psi (passed) Last tag 10290’ RKB on 10/5/2019 Has known parted liner at 10,290’ RKB Intermediate Plug – Wireline & Pumping Prepared by: Katherine O’Connor Estimated Start Date: 3-21-24 (Completed – SJG 12/18/24) Procedure 1. Punch tubing at ±9800’ RKB 2. Pump the following schedule taking returns up the IA: a. ±50 bbls surfactant wash b. ±350 bbls 9.8 brine c. ±53 bbls cement d. ±72 bbls 9.8 brine displacement 3. This should leave TOC in tubing and IA hydrostatically balanced with cement top at 8300’ MD 4. RIH and tag TOC and perform pressure test to 1500 psi (AOGCC Witnessed) 5. Cut tubing at ±3,680’ RKB Well Name Previous plug tag depth (RKB)PT Result PT/Tag Date Tubing Pressure IA Pressure OA Pressure Date of Pressures 2P-419 7889' Pass 3/30/2024 0 psi 0 psi 200 psi 3/31/2024 Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 Well Suspension Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 1 2 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3’ KB T-3 Peforations: @ 10,216' – 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB (2351' TVD) Production Tubing: 4.5” x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 /ƚĞŵĞƉƚŚͲƚŽƉƐ ;<Ϳ ϭ 'D' Esdh/E',E' Z Ϯϯ͘ϮΖ Ϯ DKΖΖE/W> tͬϯ͘ϴϳϱEK'K WZK&/> ϱϬϰ͘ϴΖ ϯ ZK^^Ks Zϰ͘ϱΗdžϯ͘ϱΗdh/E'ϵ͕ϴϯϬ͘ϯΖ ϰ < ZDh^>//E'^> s ϵ͕ϴϳϵ͘ϭΖ ϱ < ZyW,Z>/E ZdKW /^K>d/KEW< Z ϵ͕ϴϵϯΖ ϲ DKΖΖE/WW> ǁͬϮ͘ϳϱΗEK'K WZK&/> ϵ͕ϴϵϱ͘ϭΖ ϳ < Z'ͲϮϮ>KdKZ ϵ͕ϵϬϴ͘ϮΖ ϴ < ZϴϬͲϰϬ',ͲϮϮ^ > ^^ D>zǁͬ,>&Dh> ^,K ϵ͕ϵϬϵ͘ϰΖ ϵ Z^W<K&&^ >E/WW> ϵ͕ϵϭϭ͘ϵΖ ϭϬ < Z&> yͲ>K<>/E Z,E' Z ϵ͕ϵϭϰ͘ϳΖ ϭϭ < ZϴϬͲϰϬ^ >KZ yd E^/KE ϵ͕ϵϮϰ͘ϳΖ ϭϮ ZK^^Ks Zh^,/E' ϵ͕ϵϰϯ͘ϯΖ 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943’ KB Plug #1 – Reservoir TOC ±10170' RKB C80 @ 3530' KB C80 @ 3530' KB Plug #2 – Intermediate TOC ±7889' RKB BOC @ ±9800' RKB Surface Casing Plugs – Rig Prepared by: Sydney Long Estimated Start Date: 4-29-2024 1-19-202 MIRU 1. MIRU on 2P-419. (No BPV due to abandonment of all perforations.) 2. Record shut-in pressures on the T & IA. If there is pressure, bleed oƯ IA and/or tubing pressure and complete 30-minute NFT. Verify well is dead before proceeding. 3. ND Tree and NU BOPE. Test rams and annular to 250/3,000 2,500 PSI. a. Will not set BPV due to two tested cement plugs below providing two barriers to formation. b. BOPE ConƱguration: Annular / Variable Bore Rams / Blind Rams / Pipe Rams 4. Circulate tubing and IA to brine. Retrieve Tubing 5. MU landing joint and BOLDS. 6. Pull tubing from pre-rig cut to surface and LD. Execute First Surface Casing Abandonment Plug 1. Set bridge plug in production casing 100’ below surface casing shoe 2. Cut production casing 50’ below surface casing shoe 3. Circulate OA to brine and complete 30-minute NFT. a. Punch holes in production casing at the surface casing shoe if unable to achieve circulation from production casing cut. 4. MU landing joint for production casing hanger and conƱrm casing is free from cut. a. Contingency: If unable to pull production casing from original cut depth i. Perform second cut inside surface casing shoe ii. Pull casing down to upper cut and laydown iii. PU DP and Ʊshing assembly iv. TIH and engage cut stub of prod casing. Fish stub free. v. Retrieve to surface. LD DP 5. Pump cement plug through the production casing cut. Utilize 18 33 BBL of cement, plus excess, to target a Ʊnal TOC ±150’ TVD inside the surface casing shoe. Slightly under displace cement and pull 7” casing slowly to above Ʊnal TOC - allowing cement to Ʊll the space vacated by the casing displacement. Ensure base of 7” casing is between 150’ – 200’ inside the surface casing shoe based on space out of MD above target TOC and space out with a casing collar at the Ʋoor. Circulate the base of the prod casing clear of any residual cement. See table below for cement volume calculations. a. Contingency: if unable to pull prod casing from original cut depth i. TIH with tubing to above the casing shoe ii. Pump cement plug across the shoe through the tubing. PU and circulate the base of the tubing clear b. A Variance is requested to 20 AAC 25.112 requiring cement 100’ below hydrocarbon bearing zones. It is our intention to recover 50’ of production casing from the open hole section. c. A Variance is requested to Order 196 requiring the cement to be logged. It is not our intention, nor recommendation for the integrity of the abandonment, to drill out the cement plug once pumped. 6. WOC 7. Tag cement and PT to 1,500 PSI with state witness a. Pressure up to FIT equivalent and hold for 10 min to ensure no leak oƯ prior to increasing pressure to full 1,500 PSI for 30-min state witness Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 Surface Shoe Plug Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 1 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3’ KB T-3 Peforations: @ 10,216' – 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB (2351' TVD) Production Tubing: 4.5” x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 /ƚĞŵĞƉƚŚͲƚŽƉƐ ;<Ϳ ϭ 'D' Esdh/E',E' Z Ϯϯ͘ϮΖ Ϯ ĂƐƚ/ƌŽŶƌŝĚŐĞWůƵŐ ϯϯϵϬ͘ϬΖ ϯ ZK^^Ks Zϰ͘ϱΗdžϯ͘ϱΗdh/E'ϵ͕ϴϯϬ͘ϯΖ ϰ < ZDh^>//E'^> s ϵ͕ϴϳϵ͘ϭΖ ϱ < ZyW,Z>/E ZdKW /^K>d/KEW< Z ϵ͕ϴϵϯΖ ϲ DKΖΖE/WW> ǁͬϮ͘ϳϱΗEK'K WZK&/> ϵ͕ϴϵϱ͘ϭΖ ϳ < Z'ͲϮϮ>KdKZ ϵ͕ϵϬϴ͘ϮΖ ϴ < ZϴϬͲϰϬ',ͲϮϮ^ > ^^ D>zǁͬ,>&Dh> ^,K ϵ͕ϵϬϵ͘ϰΖ ϵ Z^W<K&&^ >E/WW> ϵ͕ϵϭϭ͘ϵΖ ϭϬ < Z&> yͲ>K<>/E Z,E' Z ϵ͕ϵϭϰ͘ϳΖ ϭϭ < ZϴϬͲϰϬ^ >KZ yd E^/KE ϵ͕ϵϮϰ͘ϳΖ ϭϮ ZK^^Ks Zh^,/E'ϵ͕ϵϰϯ͘ϯΖ 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943’ KB Plug #1 – Reservoir TOC ±10170' RKB C80 @ 3530' KB C80 @ 3530' KB Plug #3 – Surface Shoe TOC ±2939' RKB (2201' TVD) BOC @ ±3390' RKB 2 1 Plug #2 – Intermediate TOC ±7889' RKB BOC @ ±9800' RKB Base of 7” Casing hhBCPWF50$ Execute Final Abandonment Plug 8. Land workstring in casing hanger proƱle. 9. Circulate cement surface to surface until full cement returns observed on surface. See table below for cement volumes. RDMO 10. ND BOPE. NU dry hole tree. a. Note: this step may be performed prior to pumping Ʊnal surface to surface abandonment plug. 11. RDMO. Cement Plug TOC BOC Section ID BBL/FT Volume Notes Surface Shoe 3337 3387 Open Hole 8.5 0.060898 3.0 Displacement of Prod Casing Stub Included in BBL/FT calc 3287 3337 Open Hole 8.5 0.070187 3.5 2939 3287 Surface Casing 8.83 0.075742 26.4 32.9 Total Volume of Plug Surface Casing 23 2939 Surface Casing 8.83 0.066454 193.8 Displacement of Prod Casing Included in BBL/FT calculation Execute Final Abandonment Surface Excavation 12. DHD to perform drawdown test on tubing, IA, and OA 13. Remove well house. 14. Bleed oƯ T/I/O to ensure all pressure is bled oƯ the system. 15. Remove tree in preparation for excavation and casing cut. 16. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent loose ground from falling into the excavation. 17. Cut oƯ wellhead and all casing strings at 4 feet below original ground level. 18. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and photo document required. 19. Send the casing head with stub to materials shop. Photo document. 20. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information bead welded into the top. Photo document. AOGCC witness required. a. ConocoPhillips b. KRU 2P-419 c. PTD #: 204-017 d. API #: 50-103-20483-00-00 21. Remove cellar. Back Ʊll cellar with gravel/Ʊll as needed. Back Ʊll remaining hole to ground level. 22. Obtain site clearance approval from AOGCC. RDMO. 23. Report the Ʊnal P&A has been completed to the AOGCC. Photo document Ʊnal location condition after work is completed Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 Well Final P&A Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 1 2 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3’ KB T-3 Peforations: @ 10,216' – 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB (2351' TVD) Production Tubing: 4.5” x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 /ƚĞŵĞƉƚŚͲƚŽƉƐ ;<Ϳ ϭ 'D' Esdh/E',E' Z Ϯϯ͘ϮΖ Ϯ ĂƐƚ/ƌŽŶƌŝĚŐĞWůƵŐ ϯϯϵϬ͘ϬΖ ϯ ZK^^Ks Zϰ͘ϱΗdžϯ͘ϱΗdh/E'ϵ͕ϴϯϬ͘ϯΖ ϰ < ZDh^>//E'^> s ϵ͕ϴϳϵ͘ϭΖ ϱ < ZyW,Z>/E ZdKW /^K>d/KEW< Z ϵ͕ϴϵϯΖ ϲ DKΖΖE/WW> ǁͬϮ͘ϳϱΗEK'K WZK&/> ϵ͕ϴϵϱ͘ϭΖ ϳ < Z'ͲϮϮ>KdKZ ϵ͕ϵϬϴ͘ϮΖ ϴ < ZϴϬͲϰϬ',ͲϮϮ^ > ^^ D>zǁͬ,>&Dh> ^,K ϵ͕ϵϬϵ͘ϰΖ ϵ Z^W<K&&^ >E/WW> ϵ͕ϵϭϭ͘ϵΖ ϭϬ < Z&> yͲ>K<>/E Z,E' Z ϵ͕ϵϭϰ͘ϳΖ ϭϭ < ZϴϬͲϰϬ^ >KZ yd E^/KE ϵ͕ϵϮϰ͘ϳΖ ϭϮ ZK^^Ks Zh^,/E'ϵ͕ϵϰϯ͘ϯΖ 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943’ KB Plug #1 – Reservoir TOC ±10170' RKB C80 @ 3530' KB C80 @ 3530' KB Plug #4 – Surface TOC 23' RKB BOC @ ±2939' RKB 2 1 Plug #2 – Intermediate TOC ±7889' RKB BOC @ ±9800' RKB Plug #3 – Surface Shoe TOC ±2939' RKB (2201' TVD) BOC @ ±3390' RKB Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB (Tagged TOC) 7,889.0 2P-419 3/30/2024 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Annotate Tbg Cut 2P-419 3/31/2024 bworthi1 Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf NOTE: View Schematic w/ Alaska Schematic9.0 8/8/2010 ninam Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 25.4 10,065.3 5,276.3 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth … 9,946.1 Set Depth … 5,225.4 String Max No… 4 1/2 Tubing Description TUBING 4.5"x3.5" Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 23.2 23.2 0.00 HANGER 10.800 GMC GEN V TUBING HANGER 4.500 504.8 504.4 5.32 NIPPLE 5.630 'DB' NIPLE W/3.875 NO GO PROFILE CAMCO 3.875 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.3 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.0 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.4 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,007.0 1,772.8 57.98 TUBING PUNCH 3' TUBING PUNCH, 2", 7 GRAM, 6 SPF, 18 0.61" HOLES 3/30/2024 3.958 3,685.0 2,528.7 61.77 CUT WELLTEC MECHANICAL TBG CUT AT 3685' RKB 3/31/2024 3.958 9,800.0 5,162.8 65.09 TUBING PUNCH 3' TUBING PUNCH, 2", 7 GRAM, 6 SPF, 18 0.61" HOLES 3/23/2024 3.958 10,199.3 5,332.3 65.08 CIBP Set 2.62" CIBP (mid-element @ 10200' RKB) OAL=1.37' 3/9/2024 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 9,776.5 5,152.8 64.98 1 GAS LIFT DMY BK 1 0.0 11/5/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 2P-419, 3/31/2024 6:38:43 PM Vertical schematic (actual) LINER; 9,893.1-10,943.0 FLOAT SHOE; 10,941.3- 10,943.0 FLOAT COLLAR; 10,844.2- 10,845.6 LINER LANDING COLLAR; 10,811.1-10,812.3 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 CIBP; 10,199.3 PRODUCTION; 25.4-10,065.3 FLOAT SHOE; 10,063.8- 10,065.3 FLOAT COLLAR; 9,978.1- 9,979.4 XO BUSHING; 9,943.3-9,945.3 SBE; 9,924.7-9,943.3 SEAL ASSY; 9,909.4 HANGER; 9,914.7-9,924.0 NIPPLE; 9,911.9-9,914.7 LOCATOR; 9,908.2 PACKER; 9,893.1-9,912.0 NIPPLE; 9,895.1 SLEEVE; 9,879.1 TUBING PUNCH; 9,800.0 GAS LIFT; 9,776.5 Cement Plug; 7,889.0 ftKB Cement Plug; 7,889.0 ftKB STAGE COLLAR; 6,198.9- 6,201.3 CUT; 3,685.0 SURFACE; 28.1-3,286.9 FLOAT SHOE; 3,285.2-3,286.9 FLOAT COLLAR; 3,204.0- 3,205.5 TUBING PUNCH; 2,007.0 NIPPLE; 504.8 CONDUCTOR; 29.0-108.0 HANGER; 28.1-29.4 HANGER; 25.4-27.1 HANGER; 23.2 Casing 2; 0.0 Casing 1; 0.0 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev… 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE ϮWͲϰϭϵϭϰĂůĐƵůĂƚĞĚWdKΛϰϱϲϭ͛Z<^^ŚŽĞΛϯϮϴϳ͛Z</WΛϯϯϵϬ͛Z<^^ŚŽĞĐĞŵĞŶƚƉůƵŐdKΛϮϵϯϵ͛Z<WƵƚΛϯϯϰϬ͛Z<ϴϬdŽƉΛϯϱϯϬ͛Z<ϴϬĂƐĞΛϱϴϮϬ͛Z< Reviewed By: P.I. Suprv Comm ________ :ZϭϭͬϮϳͬϮϬϮϰ /ŶƐƉĞĐƚEŽ͗ƐƵƐϮϰϭϬϬϭϭϯϰϬϬϮ tĞůůWƌĞƐƐƵƌĞƐ;ƉƐŝͿ͗ ĂƚĞ/ŶƐƉĞĐƚĞĚ͗ϵͬϯϬͬϮϬϮϰ /ŶƐƉĞĐƚŽƌ͗ƌŝĂŶŝdžďLJ /ĨsĞƌŝĨŝĞĚ͕,Žǁ͍KƚŚĞƌ;ƐƉĞĐŝĨLJŝŶĐŽŵŵĞŶƚƐͿ ^ƵƐƉĞŶƐŝŽŶĂƚĞ͗ϯͬϭϴͬϮϬϮϰ η ϯϮϯͲϰϯϴ dƵďŝŶŐ͗ϲϯ /͗ϲϯ K͗ϭϵϱ KƉĞƌĂƚŽƌ͗ŽŶŽĐŽWŚŝůůŝƉƐůĂƐŬĂ͕/ŶĐ͘ KƉĞƌĂƚŽƌZĞƉ͗DĂƚƚDŝůůĞƌ ĂƚĞK'EŽƚŝĨŝĞĚ͗ϵͬϮϳͬϮϬϮϰ dLJƉĞŽĨ/ŶƐƉĞĐƚŝŽŶ͗/ŶŝƚŝĂů tĞůůEĂŵĞ͗<hWZh<Z/shD >dϮWͲϰϭϵ WĞƌŵŝƚEƵŵďĞƌ͗ϮϬϰϬϭϳϬ tĞůůŚĞĂĚŽŶĚŝƚŝŽŶ 'ŽŽĚ ^ƵƌƌŽƵŶĚŝŶŐ^ƵƌĨĂĐĞŽŶĚŝƚŝŽŶ 'ŽŽĚ ŽŶĚŝƚŝŽŶŽĨĞůůĂƌ 'ŽŽĚ ŽŵŵĞŶƚƐ >ŽĐĂƚŝŽŶǀĞƌŝĨŝĞĚďLJƵƐŝŶŐWĂĚDĂƉ͘ ^ƵƉĞƌǀŝƐŽƌŽŵŵĞŶƚƐ WŚŽƚŽĂƚƚĂĐŚĞĚ ^ƵƐƉĞŶƐŝŽŶƉƉƌŽǀĂů͗^ƵŶĚƌLJ >ŽĐĂƚŝŽŶsĞƌŝĨŝĞĚ͍ KĨĨƐŚŽƌĞ͍ &ůƵŝĚŝŶĞůůĂƌ͍ tĞůůďŽƌĞŝĂŐƌĂŵǀĂŝů͍ WŚŽƚŽƐdĂŬĞŶ͍ sZWůƵŐ;ƐͿ/ŶƐƚĂůůĞĚ͍ Ws/ŶƐƚĂůůĞĚ͍ tĞĚŶĞƐĚĂLJ͕EŽǀĞŵďĞƌϮϳ͕ϮϬϮϰ 9 9 9 9 9 2024-0930_Suspend_KRU_2P-419_photos_bb Page 1 of 1 Suspended Well Inspection – KRU 2P-419 PTD 2040170 AOGCC Inspection Rpt # susBDB241001134002 Photos by AOGCC Inspector B. Bixby 9/30/2024 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 10945'feet 7889', 10199'feet true vertical 5671' feet None feet Effective Depth measured 7889'feet 9909'feet true vertical 4357' feet 5210' feet Perforation depth Measured depth True Vertical depth Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 9946' MD 5225' TVD Packers and SSSV (type, measured and true vertical depth) 9009' MD N/A 5210' TVD N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: N/A Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG ~ Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A Packer: Baker 80-40 GBH-22 Seal Asmbly SSSV: None Dusty Freeborn dusty.freeborn@conocophillips.com (907) 265-6218Staff Project Engineer 10216-10236', 10250-10290', 10510-10570', 10644-10664' 5339-5348', 5354-5371', 5467-5493', 5527-5537' measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) ~ Gas-Mcf MD ~ Size 108' ~ ~~ Suspended ~~ ~ measured TVD 7" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 204-017 50-103-20483-00-00 P.O. Box 100360 Anchorage, AK 99510 3. Address: ConocoPhillips Alaska, Inc. N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0373112, ADL0389058 Kuparuk River Field/ Meltwater Oil Pool-Suspended KRU 2P-419 Plugs Junk measured Length Production Liner 10040' 1050' Casing 5276' 3-1/2" 10065' 10943' 5670' 3259' 108'Conductor Surface Intermediate 16" 9-5/8" 79' 3287' 2352' Burst Collapse Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:11 pm, Oct 17, 2024 Digitally signed by Dusty Freeborn DN: CN=Dusty Freeborn, O=ConocoPhillips Alaska, OU= Well Integrity and Intervention, E=Dusty.Freeborn@ conocophillips.com, C=US Reason: I am the author of this document Location: Anchorage, Alaska Date: 2024.10.16 15:04:15-08'00' Foxit PDF Editor Version: 13.0.0 Dusty Freeborn Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB (Tagged TOC) 7,889.0 2P-419 3/30/2024 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Annotate Tbg Cut 2P-419 3/31/2024 bworthi1 Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 25.4 10,065.3 5,276.3 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth 9,946.1 Set Depth 5,225.4 String Max No 4 1/2 Tubing Description TUBING 4.5"x3.5" Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 23.2 23.2 0.00 HANGER 10.800 GMC GEN V TUBING HANGER 4.500 504.8 504.4 5.32 NIPPLE 5.630 'DB' NIPLE W/3.875 NO GO PROFILE CAMCO 3.875 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.3 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.0 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.4 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 2,007.0 1,772.8 57.98 TUBING PUNCH 3' TUBING PUNCH, 2", 7 GRAM, 6 SPF, 18 0.61" HOLES 3/30/2024 3.958 3,685.0 2,528.7 61.77 CUT WELLTEC MECHANICAL TBG CUT AT 3685' RKB 3/31/2024 3.958 9,800.0 5,162.8 65.09 TUBING PUNCH 3' TUBING PUNCH, 2", 7 GRAM, 6 SPF, 18 0.61" HOLES 3/23/2024 3.958 10,199.3 5,332.3 65.08 CIBP Set 2.62" CIBP (mid-element @ 10200' RKB) OAL=1.37' 3/9/2024 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 9,776.5 5,152.8 64.98 1 GAS LIFT DMY BK 1 0.0 11/5/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 7,889.0 9,803.0 4,356.6 5,164.0 Cement Plug 3/27/2024 2P-419, 9/25/2024 11:51:43 AM M D (ft KB ) 0.0 23.3 25.3 26.2 27.2 28.2 28.9 29.5 57.4 67.9 69.2 90.2 107.9 498.7 504.9 506.2 512.1 2,006.9 2,009.8 2,745.1 2,746.1 3,204.1 3,205.4 3,285.1 3,286.7 3,287.1 3,685.0 3,686.0 4,840.6 4,871.1 6,198.2 6,198.8 6,201.4 7,889.1 8,028.9 9,483.9 9,610.9 9,770.7 9,776.6 9,783.8 9,789.7 9,799.9 9,803.1 9,820.5 9,830.4 9,832.0 9,841.9 9,873.0 9,879.3 9,882.9 9,893.0 9,895.0 9,896.0 9,908.1 9,909.4 9,912.1 9,914.7 9,923.9 9,924.9 9,943.2 9,945.2 9,946.2 9,949.1 9,978.0 9,979.3 10,029.9 10,064.0 10,065.0 10,065.3 10,107.0 10,140.1 10,147.0 10,199.5 10,200.8 10,215.9 10,235.9 10,250.0 10,290.0 10,509.8 10,529.9 10,569.9 10,644.0 10,664.0 10,755.9 10,811.0 10,812.3 10,844.2 10,845.8 10,941.3 10,942.9 10,944.9 Vertical schematic (actual) T-7 (final) T-4.1 (fi T-4.2 (fi T-3 (final) T-3.1 (fi T-2 (final) FLOAT SHOE; 10,941.3-10,943.0; 1.72; 4-13; 3.500; 2.992 LINER; 10,845.6-10,941.3; 95.64; 4-12; 3.500; 2.992 FLOAT COLLAR; 10,844.2-10,845.6; 1.41; 4-11; 3.500; 2.992 LINER; 10,812.3-10,844.2; 31.94; 4-10; 3.500; 2.992 LINER LANDING COLLAR; 10,811.1-10,812.3; 1.23; 4-9; 3.500; 2.992 IPERF; 10,644.0-10,664.0; 3/6/2004 IPERF; 10,530.0-10,570.0; 3/7/2004 IPERF; 10,510.0-10,530.0; 3/8/2004 LINER; 9,949.0-10,811.1; 862.07; 4-8; 3.500; 2.992 IPERF; 10,250.0-10,290.0; 2/26/2014 IPERF; 10,216.0-10,236.0; 3/1/2014 FLOAT SHOE; 10,063.8-10,065.3; 1.46; 3-7; 7.000; 6.276 PRODUCTION; 9,979.4-10,063.8; 84.45; 3-6; 7.000; 6.276 FLOAT COLLAR; 9,978.1-9,979.4; 1.31; 3-5; 7.000; 6.276 LINER PUP; 9,945.3-9,949.0; 3.73; 4-7; 3.500; 2.992 XO BUSHING; 9,943.3-9,945.3; 1.97; 4-6; 5.570; 3.000 SBE; 9,924.7-9,943.3; 18.56; 4-5; 5.000; 4.000 SEAL ASSY; 9,909.4-9,946.1; 36.64; 2-25; 4.000; 3.000 LINER COUPLING; 9,924.0-9,924.7; 0.76; 4-4; 5.570; 4.380 HANGER; 9,914.7-9,924.0; 9.30; 4-3; 7.000; 5.000 NIPPLE; 9,911.9-9,914.7; 2.72; 4-2; 5.500; 4.250 LOCATOR; 9,908.2-9,909.4; 1.22; 2-24; 5.000; 3.000 PACKER; 9,893.1-9,912.0; 18.90; 4-1; 7.000; 5.000 TUBING PUP; 9,896.1-9,908.2; 12.15; 2-23; 3.500; 2.992 NIPPLE; 9,895.1-9,896.1; 1.00; 2-22; 4.500; 2.750 TUBING PUP; 9,883.0-9,895.1; 12.04; 2-21; 3.500; 2.992 SLEEVE; 9,879.1-9,883.0; 3.91; 2-20; 4.500; 2.812 TUBING PUP; 9,873.0-9,879.1; 6.09; 2-19; 3.500; 2.992 TUBING; 9,842.0-9,873.0; 31.00; 2-18; 3.500; 2.992 TUBING PUP; 9,832.0-9,842.0; 10.04; 2-17; 3.500; 2.992 XO Reducing; 9,830.3-9,832.0; 1.66; 2-16; 5.200; 2.991 TUBING PUP; 9,820.5-9,830.3; 9.84; 2-15; 4.500; 3.958 TUBING; 9,789.7-9,820.5; 30.75; 2-14; 4.500; 3.958 TUBING PUP; 9,783.8-9,789.7; 5.94; 2-13; 4.500; 3.958 GAS LIFT; 9,776.5-9,783.8; 7.31; 2-12; 5.984; 3.938 TUBING PUP; 9,770.7-9,776.5; 5.79; 2-11; 4.500; 3.958 PRODUCTION; 6,201.3-9,978.1; 3,776.78; 3-4; 7.000; 6.276 TUBING; 4,871.1-9,770.7; 4,899.57; 2-10; 4.500; 3.958 STAGE COLLAR; 6,198.9-6,201.3; 2.34; 3-3; 7.000; 6.276 TUBING xo PIPE TYPE; 4,840.7-4,871.1; 30.41; 2-9; 4.500; 3.958 FLOAT SHOE; 3,285.2-3,286.9; 1.72; 2-7; 9.625; 8.835 SURFACE; 3,205.5-3,285.2; 79.68; 2-6; 9.625; 8.835 FLOAT COLLAR; 3,204.0-3,205.5; 1.50; 2-5; 9.625; 8.835 PRODUCTION; 27.1-6,198.9; 6,171.83; 3-2; 7.000; 6.276 TUBING; 512.2-4,840.7; 4,328.52; 2-8; 4.500; 3.958 SURFACE; 90.2-3,204.0; 3,113.75; 2-4; 9.625; 8.835 TUBING PUP; 506.3-512.2; 5.94; 2-7; 4.500; 3.958 NIPPLE; 504.8-506.3; 1.49; 2-6; 5.630; 3.875 TUBING PUP; 498.8-504.8; 5.92; 2-5; 4.500; 3.958 TUBING; 69.3-498.8; 429.54; 2-4; 4.500; 3.958 SURFACE PUP; 68.0-90.2; 22.20; 2-3; 9.625; 8.835 CONDUCTOR; 29.0-108.0; 79.00; 1-1; 16.000; 15.062 TUBING PUP; 57.3-69.3; 12.00; 2-3; 4.500; 3.958 SURFACE; 29.4-68.0; 38.65; 2-2; 9.625; 8.835 TUBING; 26.2-57.3; 31.08; 2-2; 4.500; 3.958 HANGER; 28.1-29.4; 1.27; 2-1; 12.000; 9.625 HANGER; 25.4-27.1; 1.71; 3-1; 10.000; 6.151 HANGER; 23.2-26.2; 3.04; 2-1; 10.800; 4.500 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE ORIGINATED TRANSMITTAL DATE: 6/23/2024 ALASKA E-LINE SERVICES TRANSMITTAL #: 4739 42260 Kenai Spur Hwy PO BOX 1481 - Kenai, Alaska 99611 FIELD Meltwater PH: (907) 283-7374 FAX: (907) 283-7378 DELIVERABLE DESCRIPTION TICKET # WELL # API # LOG DESCRIPTION DATE OF LOG 4739 2P-419 501032048300 Tubing Punch 23-Mar-2024 RECIPIENTS Conoco Phillips Alaska, Inc. DIGITAL FILES PRINTS CD'S 1 0 0 0 USPS 0 0 0 0 Received By: Received By: Signature Signature AOGCC DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resources Technician II abby.bell@alaska.gov Alaska Oil & Gas Conservation Commision 333 W. 7th Ave, Suite 100 - Anchorage, AK 99501 Received By: Received By: Signature Signature 204-017 T39058 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.06.26 15:22:05 -08'00' DNR DIGITAL FILES PRINTS CD'S 1 SharePoint Link 0 0 USPS Attn: Natural Resource Tech II DOG.Redata@alaska.gov 550 West 7th Ave, Suite #802 - Anchorage, AK 99501 Delivery Method: USPS Received By: Received By: Signature Signature Please return via e-mail a copy to both: AR@ake- line.com 0 204-017 T38910 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.06.12 14:50:29 -08'00' 204-017 T38910 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2024.06.12 14:49:40 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:17 Township:8N Range:7E Meridian:Umiat Drilling Rig:n/a Rig Elevation:n/a Total Depth:10945 ft MD Lease No.:ADL 373112 Operator Rep:Suspend:P&A:X Conductor:16"O.D. Shoe@ 108 Feet Csg Cut@ Feet Surface:9 5/8"O.D. Shoe@ 3287 Feet Csg Cut@ Feet Intermediate:O.D. Shoe@ Feet Csg Cut@ Feet Production:7"O.D. Shoe@ 10065 Feet Csg Cut@ Feet Liner:3 1/2"O.D. Shoe@ 10943 Feet Csg Cut@ Feet Tubing:4 1/2"O.D. Tail@ 9946 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Fullbore Balanced 10140 ft 7889 ft 6.8 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1718 1652 1623 IA 1718 1652 1624 OA 273 243 227 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Cement tag was solid at 7889 ft MD and got a good sample from bailer. On pressure test we had 1.0 bbls in and 0.9 bbls back. March 30, 2024 Kam StJohn Well Bore Plug & Abandonment KRU 2P-419 ConocoPhillips Alaska LLC PTD 2040170; Sundry 324-161 Photos (2) Test Data: P Casing Removal: rev. 3-24-2022 2024-0324_Plug_Verification_KRU_2P-419_ksj 2024-0324_Plug_Verifica�on_KRU 2P-419_photos_ksj Page 1 of 1 Plug Verification – KRU 2P-419 (PTD 2040170) Photos by AOGCC Inspector K. StJohn 3/24/2024 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: ___________________ Service Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address: 7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:17. Field / Pool(s): GL: BF: Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- y- Zone- 4 TPI: x- y- Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22. Logs Obtained: N/A 23. BOTTOM 16" B 108' 9.625" L-80 2352' 7" L-80 5276' 3.5" L-80 5670' 24. Open to production or injection? Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production: Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press. 24-Hour Rate Sr Res EngSr Pet GeoSr Pet Eng N/A Oil-Bbl: Water-Bbl: 10140'-10199' 11 gal 15.6 ppg Cement on top of CIBP Water-Bbl: PRODUCTION TEST N/A Date of Test: Oil-Bbl: Flow Tubing SUSPENDED 10216-10236' MD and 5339-5348' TVD 10250-10290' MD and 5354-5371' TVD 10510-10570' MD and 5467-5493' TVD 10644-10664' MD and 5527-5537' TVD Gas-Oil Ratio:Choke Size: Per 20 AAC 25.283 (i)(2) attach electronic information 26# 10943' Surface 5289' 62.5# 40# 108' Surface 10065' SIZE DEPTH SET (MD) 9893' PACKER SET (MD/TVD) 42" 12.25" 110 sx LiteCrete Surface 396 sx AS Lite, 297 sx LiteCrete 9.3# Surface 9893' 3287'Surface Surface CASING WT. PER FT.GRADE 2/5/2004 CEMENTING RECORD 5861918 1399' MD/ 1355' TVD SETTING DEPTH TVD 5861297 TOP HOLE SIZE AMOUNT PULLED 442058 441641 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. N/A Kuparuk River Field/ Meltwater- Suspended BOTTOM 50-103-20483-00-00 KRU 2P-419 ADL0373112, ADL0389058 888' FNL, 2148' FWL, Sec. 17, T8N, R7E, UM 1962' FSL, 287' FEL, Sec. 19, T8N, R7E, UM ALK 4998/L32092/32409 1/21/2004 10945' MD/ 5671' TVD 10140' MD/ 5307' TVD P.O. Box 100360, Anchorage, AK 99510-0360 444108 5868988 2587' FSL, 127' FWL, Sec. 20, T8N, R7E, UM 9. Ref Elevations: KB: 28' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ConocoPhillips Alaska, Inc. WAG Gas 3/18/2024 204-017/ 323-438 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): ACID, FRACTURE, CEMENT SQUEEZE, ETC. CASING, LINER AND CEMENTING RECORD List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, 51.7 bbls Class G6.125" TUBING RECORD 223 sx Class G, 209 sx Class G8.5" 9946'4.5" x 3.5" Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 1:27 pm, Mar 21, 2024 Suspended 3/18/2024 JSB RBDMS JSB 040424 xGDSR-4/23/24 Conventional Core(s): Yes No Sidewall Cores: N/A 30. MD TVD Surface Surface 1399' 1355' Top of Productive Interval N/A 31. List of Attachments: Schematics, Summary of Operations 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Katherine O'Connor Digital Signature with Date:Contact Email: katherine.oconnor@conocophillips.com Contact Phone:(907) 263-3718 Senior Well Interventions Engineer General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Authorized Name and N/A - Suspended INSTRUCTIONS Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Authorized Title: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Formation Name at TD: If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered) FORMATION TESTS N/A - Suspended Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O=ConocoPhillips, OU=Wells Group, E=katherine.oconnor@conocophillips.com, C=US Reason: I am the author of this document Location:Date: 2024.03.21 08:51:42-08'00' Foxit PDF Editor Version: 13.0.0 Katherine O'Connor Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: RKB (Tagged TOC) 10,140.0 2P-419 3/18/2024 rogerba Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Update Tag depth 2P-419 3/18/2024 rogerba Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf NOTE: View Schematic w/ Alaska Schematic9.0 8/8/2010 ninam Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 25.4 10,065.3 5,276.3 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth … 9,946.1 Set Depth … 5,225.4 String Max No… 4 1/2 Tubing Description TUBING 4.5"x3.5" Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 23.2 23.2 0.00 HANGER 10.800 GMC GEN V TUBING HANGER 4.500 504.8 504.4 5.32 NIPPLE 5.630 CAMCO 'DB' NIPLE W/3.875 NO GO PROFILE 3.875 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.3 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.0 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.4 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 10,199.3 5,332.3 65.08 CIBP Set 2.62" CIBP (mid-element @ 10200' RKB) OAL=1.37' 3/9/2024 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 9,776.5 5,152.8 64.98 1 GAS LIFT DMY BK 1 0.0 11/5/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase Cement Squeezes Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Des Com Pump Start Date 10,140.0 10,199.3 5,307.5 5,332.3 Cement Plug Dump bail 15.6 ppg cement with Slickline on top of CIBP 3/12/2024 2P-419, 3/20/2024 4:39:18 PM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 CIBP; 10,199.3 Cement Plug; 10,140.0 ftKB PRODUCTION; 25.4-10,065.3 GAS LIFT; 9,776.5 SURFACE; 28.1-3,286.9 NIPPLE; 504.8 CONDUCTOR; 29.0-108.0 Casing 1; 0.0 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev… 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE DTTMSTART JOBTYP SUMMARYOPS 7/31/2023 ACQUIRE DATA MEASURED SBHP @ 9879' RKB (MAX = 2912 PSI), DRIFTED TBG W/ 15' X 2.70" DMY CIBP DRIFT TO 10,073' RKB, 93' SHORT OF TARGET DEPTH, LRS DISPLACED TBG W/ 135 BBL DIESEL. JOB IN PROGRESS. 8/2/2023 ACQUIRE DATA DRIFT TBG W/ 15' X 2.70" DMY CIBP DRIFT TO 10,173' RKB, NO TIGHT SPOTS OR WEIGHT SWINGS FOUND. JOB COMPLETE. 2/19/2024 CHANGE WELL TYPE MIT-IA TO 2000 PSI (PASSED) 2/29/2024 ACQUIRE DATA (SUSPEND WELL) FUNCTION TEST LDS/GN (COMPLETE) IC POT (PASS) IC PPPOT (PASS), T POT (PASS), T PPPOT (PASS) 3/9/2024 ACQUIRE DATA LOAD TBG W/ 57.5 BBLS OF 10.6 BRINE & 150 BBLS DIESEL, SET 2.65" CAST IRON BRIDGE PLUG @ 10200' RKB, MIT TBG 2500 PSI (PASS). IN PROGRESS. 3/12/2024 ACQUIRE DATA DUMPED 4.4 GALLONS 15.6 ppg CEMENT ON TOP OF CIBP @ 10200' RKB...IN PROGRESS 3/13/2024 ACQUIRE DATA DUMPED 2.2 GALLONS OF 15.6 LBS / GAL CEMENT ON CIBP @ 10200' RKB (23' x CEMENT ABOVE CIBP TO DATE).....IN PROGRESS 3/15/2024 ACQUIRE DATA DUMPED 4.4 GALLONS OF 15.6 LBS / GAL CEMENT ON CIBP @ 10200' RKB ....TAGGED CEMENT @ ~10147' RKB. READY FOR SW TAG & TEST IN 48 HOURS. 3/18/2024 ACQUIRE DATA STATE WITNESS TAG TOC @ 10140' RKB, STATE WITNESS MITT TO 1750 PSI ( PASSED) 3/19/2024 ACQUIRE (SECURE) T-DDT TO 0 PSI (PASSED) 2P-419 Suspend Summary of Operations MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:17 Township:8N Range:7E Meridian:Umiat Drilling Rig:NA Rig Elevation:NA Total Depth:10945 ft MD Lease No.:ADL0373112 Operator Rep:Suspend:X P&A:NA Conductor:16"O.D. Shoe@ 108 Feet Csg Cut@ NA Feet Surface:9-5/8"O.D. Shoe@ 3287 Feet Csg Cut@ NA Feet Intermediate:NA O.D. Shoe@ NA Feet Csg Cut@ NA Feet Production:7"O.D. Shoe@ 10065 Feet Csg Cut@ NA Feet Liner:3-1/2"O.D. Shoe@ 10943 Feet Csg Cut@ NA Feet Tubing:4-1/2"x3-1/2"O.D. Tail@ 9946 Feet Tbg Cut@ NA Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Bridge plug 10200 ft MD 10140 ft MD 8.6/6.9 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 1750 1720 1710 IA 815 815 810 OA 190 190 190 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: I traveled to KRU 2P to witness the tag and pressure test of the bottom, zone isolating cement plug that had been dumped bailed on 3/12/2024 on top of a cast iron bridge plug (CIBP) inside the wells 3-1/2 inch production string. CIBP was set at 10200 ft MD putting it 16 feet above the top perforation. They ran in the hole with generic 2-1/2 inch slickline bailer string and tagged at 10140 ft MD (65°inclination) with multiple jars down. At surface we found cement in the bailer. Then achieved a passing mechanical integrity test of the plug/production string. No issues with this inspection. March 18, 2024 Austin McLeod Well Bore Plug & Abandonment Kuparuk River Unit 2P-419 ConocoPhillips Alaska, Inc. PTD 2040170; Sundry 323-438 Test Data: P Casing Removal: John Hansen Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2024-0318_Plug_Verification_KRU_2P-419_am Operations shutdownRepair WellFracture StimulatePlug PerforationsAbandon1. Type of Request: Change Approved ProgramPull TubingOther StimulatePerforateSuspend Other: ___________________Alter CasingPerforate New Pool Re-enter Susp WellPlug for Redrill 5. Permit to Drill Number:4. Current Well Class:2. Operator Name: DevelopmentExploratory 3. Address:ServiceStratigraphic 6. API Number: 8. Well Name and Number:7. If perforating: What Regulation or Conservation Order governs well spacing in this pool? NoYes 10. Field:9. Property Designation (Lease Number): 11. Junk (MD):Effective Depth TVD:Effective Depth MD:Total Depth TVD (ft):Total Depth MD (ft): None10945' CollapseCasing Structural Conductor Surface Intermediate Production Liner Packers and SSSV MD (ft) and TVD (ft):Packers and SSSV Type: 13. Well Class after proposed work:12. Attachments: Proposal Summary Wellbore schematic ServiceDevelopmentExploratory StratigraphicDetailed Operations Program BOP Sketch 15. Well Status after proposed work:14. Estimated Date for WDSPLOIL WINJCommencing Operations:Suspended SPLUGGSTORWAGGASDate:16. Verbal Approval: AOGCC Representative: GINJ AbandonedOp Shutdown Contact Name: Contact Email: Contact Phone: Authorized Title: Sundry Number:Conditions of approval: Notify AOGCC so that a representative may witness Location ClearancePlug Integrity BOP Test Mechanical Integrity Test Other Conditions of Approval: Post Initial Injection MIT Req'd? NoYes APPROVED BY Date:THE AOGCCCOMMISSIONERApproved by: Sr Res EngSr Pet GeoSr Pet EngComm.Comm. (907) 265-6312 Senior RWO/CTD Engineer KRU 2P-419 None26095671'10945'5671' N/A Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: Plugs (MD):MPSP (psi): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: sydney.long@conocophillips.com AOGCC USE ONLY Tubing MD (ft):Tubing Grade: 9893' MD and 5202' TVD 9909' MD and 5210' TVD N/A Sydney Long STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 204-017 P.O. Box 100360, Anchorage, AK 99510 50-103-20483-00 Kuparuk River Field Meltwater Oil Pool-Suspended ConocoPhillips Alaska, Inc. SizeLength PRESENT WELL CONDITION SUMMARY BurstTVD 9946' MD 108' 2352' 108' 3287' 5276'10065' 16" 9-5/8" 79' 3259' 10216-10236', 10250-10290', 10510-10570', 10644-10664' 10040' 3-1/2" 5339-5348', 5354-5371', 5467- 5493', 5527-5537' 7" Perforation Depth TVD (ft): 10943'1050' 4-1/2" 5670' Packer: Baker ZXP Liner Top Packer Packer: Baker 80-40 GHB-22 Seal Assy SSSV: None Perforation Depth MD (ft): L-80 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Proposed Pools: Meltwater Oil Pool - Abandoned 3/21/2024 By Grace Christianson at 9:17 am, Mar 13, 2024 AOGCC inspection required after cutoff and before remedial cementing X BOP test to 2500 psig; Annular preventer test to 2500 psig. A variance to 20 AAC 25.112(a)(1)(A) is granted. Cement is not required from 100' below the base of the C-80 to 100' above the top of the C-80. The variance is granted to allow an equally effective plug which includes the placement of a cement plug from ~50' MD below the surface casing shoe in the open hole to 150' MD into the surface casing. (20 AAC 25.112(i)) A variance to the cement logging required in Other Order 196 is granted. Cement logging is not required. X VTL 03/21/2024 X DSR-3/14/24 10-407 A.Dewhurst 13MAR24JLC 3/22/2024 2P-419Plug and Abandonment Background & Objective 2P-417 was an injector that has been shut in since March 2021. This well is in progress of being suspended with a CIBP and cement (as of 3/7/2024). The steps to P&A this well include three more cement plugs: an intermediate plug across the tubing, a plug across the surface casing shoe after the tubing and production casing has been pulled, and then a final plug to surface. Well Data Meltwater Formation: Reservoir pressure 7/31/2023= 2912 PSI@ 4944 TVD MASP = 2609 psi C-80 Formation: OAP = 199 psi (11/5/2022) (fluid packed with diesel) MASP = 783 psi (0.1 PSI/FT gradient) Last MITIA 8/16/2022 to 3590 psi (passed) Last tag 10290 RKB on 10/5/2019 Has known parted liner at 10,290 RKB Intermediate Plug Wireline & Pumping Prepared by: Katherine OConnor Estimated Start Date: 3-21-24 Procedure 1. Punch tubing at ±9800 RKB 2. Pump the following schedule taking returns up the IA: a. ±50 bbls surfactant wash b. ±350 bbls 9.8 brine c. ±53 bbls cement d. ±72 bbls 9.8 brine displacement 3. This should leave TOC in tubing and IA hydrostatically balanced with cement top at 8300 MD 4. RIH and tag TOC and perform pressure test to 1500 psi (AOGCC Witnessed) 5. Cut tubing at ±3,680 RKB Surface Casing Plugs Rig Prepared by: Sydney Long Estimated Start Date: 4-29-2024 MIRU 1. MIRU on 2P-419. (No BPV due to abandonment of all perforations.) 2. Record shut-in pressures on the T & IA. If there is pressure, bleed o IA and/or tubing pressure and complete 30-minute NFT. Verify well is dead before proceeding. 3. ND Tree and NU BOPE. Test rams and annular to 250/3,000 PSI. a. Will not set BPV due to two tested cement plugs below providing two barriers to formation. b. BOPE Con guration: Annular / Variable Bore Rams / Blind Rams / Pipe Rams 4. Circulate tubing and IA to brine. Retrieve Tubing 5. MU landing joint and BOLDS. 6. Pull tubing from pre-rig cut to surface and LD. Execute First Surface Casing Abandonment Plug 1. Set bridge plug in production casing 100 below surface casing shoe 2. Cut production casing 50 below surface casing shoe 3. Circulate OA to brine and complete 30-minute NFT. a. Punch holes in production casing at the surface casing shoe if unable to achieve circulation from production casing cut. 4. MU landing joint for production casing hanger and con rm casing is free from cut. a. Contingency: If unable to pull production casing from original cut depth i. Perform second cut inside surface casing shoe ii. Pull casing down to upper cut and laydown iii. PU DP and shing assembly iv. TIH and engage cut stub of prod casing. Fish stub free. v. Retrieve to surface. LD DP 5. Pump cement plug through the production casing cut. Utilize 18 BBL of cement, plus excess, to target a nal TOC ±150 inside the surface casing shoe. Slightly under displace cement and pull 7 casing slowly to above nal TOC - allowing cement to ll the space vacated by the casing displacement. Ensure base of 7 casing is between 150 200 inside the surface casing shoe based on space out of a casing collar at the oor. Circulate the base of the prod casing clear of any residual cement. See table below for cement volume calculations. a. Contingency: if unable to pull prod casing from original cut depth i. TIH with tubing to above the casing shoe ii. Pump cement plug across the shoe through the tubing. PU and circulate the base of the tubing clear b. A Variance is requested to 20 AAC 25.112 requiring cement 100 below hydrocarbon bearing zones. It is our intention to recover 50 of production casing from the open hole section. c. A Variance is requested to Order 196 requiring the cement to be logged. It is not our intention, nor recommendation for the integrity of the abandonment, to drill out the cement plug once pumped. 6. WOC 7. Tag cement and PT to 1,500 PSI with state witness a. Pressure up to FIT equivalent and hold for 10 min to ensure no leak o prior to increasing pressure to full 1,500 PSI for 30-min state witness Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 Surface Shoe Plug Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 1 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3 KB T-3 Peforations: @ 10,216' 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB Production Tubing: 4.5 x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943 KB Plug #1 Reservoir TOC ±10170' RKB C80 @ 3530' KB C80 @ 3530' KB Plug #3 Surface Shoe TOC ±3140' RKB BOC @ ±3390' RKB 2 1 Plug #2 Intermediate TOC ±8300' RKB BOC @ ±9800' RKB Execute Final Abandonment Plug 8. Land workstring in casing hanger pro le. 9. Circulate cement surface to surface until full cement returns observed on surface. See table below for cement volumes. RDMO 10. ND BOPE. NU dry hole tree. 11. RDMO. Cement Plug TOC BOC Section ID BBL/FT Volume Notes Surface Shoe 3337 3387 Open Hole 8.5 0.060898 3.0 Displacement of Prod Casing Stub Included in BBL/FT calc 3287 3337 Open Hole 8.5 0.070187 3.5 3137 3287 Surface Casing 6.28 0.066454 11.4 17.9 Total Volume of Plug Surface Casing 23 3137 Surface Casing 6.28 0.066454 207.1 Displacement of Prod Casing Included in BBL/FT calculation Execute Final Abandonment Surface Excavation 12. DHD to perform drawdown test on tubing, IA, and OA 13. Remove well house. 14. Bleed o T/I/O to ensure all pressure is bled o the system. 15. Remove tree in preparation for excavation and casing cut. 16. If shallow thaw conditions are found, have shoring box installed during the excavation activity to prevent loose ground from falling into the excavation. 17. Cut o wellhead and all casing strings at 4 feet below original ground level. 18. Perform top job if needed to ensure cement is at surface on all strings. AOGCC witness and photo document required. 19. Send the casing head with stub to materials shop. Photo document. 20. Weld 1/4" thick cover plate (16" OD) over all casing strings with the following information bead welded into the top. Photo document. AOGCC witness required. a. ConocoPhillips b. KRU 2P-419 c. PTD #: 204-017 d. API #: 50-103-20483-00-00 21. Remove cellar. Back ll cellar with gravel/ll as needed. Back ll remaining hole to ground level. 22. Obtain site clearance approval from AOGCC. RDMO. 23. Report the nal P&A has been completed to the AOGCC. Photo document nal location condition after work is completed Production Casing Cement Stage 1: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 8,002' KB Liner Cement: 51.7 bbls of 15.8# Class G Cement Calculated TOC @ 9,893' KB 2P-419 Final P&A Schematic Conductor: 16" Conductor 108' KB Production Casing Cement Stage 2: 83.6 bbls of 15.8# Class G Cement Calculated TOC @ 4,561' KB BOC @ 6,198.9' 1 2 4 6 Production Casing: 7" 26# L-80 BTC Mod Set @ 10,065.3 KB T-3 Peforations: @ 10,216' 10,664' KB (448') Surface Casing: 9-5/8", 40#, L-80 BTC Set @ 3,286.9' KB Production Tubing: 4.5 x 3.5" @ 9,830.3', 12.6# x 9.3# L-80 IBT-MOD Set @ 9,946.1' KB 8 3 7 9 5 10 11 12Liner: 3.5" 9.2# L-80 SLHT Set @ 10,943 KB Plug #1 Reservoir TOC ±10170' RKB C80 @ 3530' KB C80 @ 3530' KB Plug #3 Surface Shoe TOC ±3140' RKB BOC @ ±3390' RKB Plug #4 Surface TOC 23' RKB BOC @ ±3140' RKB 2 1 Plug #2 Intermediate TOC ±8300' RKB BOC @ ±9800' RKB Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM 10,282.0 2P-419 4/22/2016 pproven Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Set 2.65 CIBP @10200' RKB 2P-419 3/10/2024 jhanse11 Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf NOTE: View Schematic w/ Alaska Schematic9.0 8/8/2010 ninam Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 25.4 10,065.3 5,276.3 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: "String Max Nominal OD" is the OD of the LONGEST segment in string Top (ftKB) 23.2 Set Depth 9,946.1 Set Depth 5,225.4 String Max No 4 1/2 Tubing Description TUBING 4.5"x3.5" Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 23.2 23.2 0.00 HANGER 10.800 GMC GEN V TUBING HANGER 4.500 504.8 504.4 5.32 NIPPLE 5.630 CAMCO 'DB' NIPLE W/3.875 NO GO PROFILE 3.875 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.3 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.0 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.4 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top (ftKB) Top (TVD) (ftKB)Top Incl (°)Des Com Make Model SN Run Date ID (in) 10,200.0 5,332.6 65.07 CIBP Set 2.65 CIBP @ 10200' RKB 3/9/2024 0.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 9,776.5 5,152.8 64.98 1 GAS LIFT DMY BK 1 0.0 11/5/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 2P-419, 3/10/2024 8:43:45 AM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 PRODUCTION; 25.4-10,065.3 GAS LIFT; 9,776.5 SURFACE; 28.1-3,286.9 NIPPLE; 504.8 CONDUCTOR; 29.0-108.0 Casing 1; 0.0 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. You don't often get email from katherine.oconnor@conocophillips.com. Learn why this is important From:Davies, Stephen F (OGC) To:O"Connor, Katherine Cc:Loepp, Victoria T (OGC); Dewhurst, Andrew D (OGC) Subject:RE: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-144) - Question Date:Monday, March 18, 2024 1:17:37 PM Thank you, Katherine. The erroneous calculated cement top of 5,782 MD is based on 62-1/2 barrels of cement, 6-3/4 hole diameter, 30% hole washout, and a production casing string consisting of only 5-1/2 pipe (forgetting that a significant portion of that production casing string actually consists of 3-1/2 pipe). Could you please check the calculated TOCs on schematic drawings that accompany all future Sundry Applications? Thanks for your help, Steve Davies AOGCC From: O'Connor, Katherine <Katherine.OConnor@conocophillips.com> Sent: Monday, March 18, 2024 12:54 PM To: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: RE: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-144) - Question Hi Steve I just pulled the drilling record, and confirmed there was 62.5 bbls of cement pumped. Using that and the 6-3/4 hole size, I calculate TOC outside the casing being ~7000 KB depending on how many digits I carry through in my calcs. So unsure how whomever made the schematic got to 5782 KB. Thanks Katherine Katherine OConnor CPF2 Interventions Engineer 907-263-3718 (O) 214-684-7400 (C) From: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Sent: Monday, March 18, 2024 12:09 PM To: O'Connor, Katherine <Katherine.OConnor@conocophillips.com> Cc: Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov>; Dewhurst, Andrew D (OGC) <andrew.dewhurst@alaska.gov> Subject: [EXTERNAL]RE: KRU 2P-415A (Permit 201-226; Sundry 324-144) - Question CAUTION:This email originated from outside of the organization. Do not click links or open attachments unless you recognize the sender and know the content is safe. Hi Katherine, Im reviewing CPAIs revised Sundry Application for KRU 2P-415A. This is a minor point, but to ensure that AOGCCs well records are accurate could you please confirm the calculated top of cement for the 5.5 x 3.5 production casing string that is shown on the wellbore schematic drawing as 5,782 MD? Cheers and Be Well, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10945'None Casing Collapse Structural Conductor Surface Intermediate Production Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 8/21/2023 10943'1050' 4-1/2" x 3-1/2" 5670' Packer: Baker ZXP HR Liner Top Packer SSSV: None Perforation Depth MD (ft): L-80 3259' 10216-10236', 10250-10290', 10510-10570', 10644-10664' 10040' 3-1/2" 5339-5348', 5354-5371', 5467- 5493', 5527-5537' 7" Perforation Depth TVD (ft): 108' 3287' 5276'10065' 16" 9-5/8" 79' 9946' MD 108' 2352' ConocoPhillips Alaska, Inc. Length Size Proposed Pools: PRESENT WELL CONDITION SUMMARY Meltwater Oil Pool- Suspended TVD Burst STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0373112, ADL0389058 204-017 P.O. Box 100360, Anchorage, AK 99510 50-103-20483-00-00 Kuparuk River Field Meltwater Oil Pool AOGCC USE ONLY Tubing Grade: Tubing MD (ft): 9893' MD and 5202' TVD N/A Katherine O'Connor Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: katherine.oconnor@conocophillips.com (907) 263-3718 Well Interventions Engineer KRU 2P-419 5671' 10290' 5371' 2633 None N/A Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 7:40 am, Aug 03, 2023 Digitally signed by Katherine O'Connor DN: CN=Katherine O'Connor, O=ConocoPhillips, OU=Wells Group, E=katherine.oconnor@ conocophillips.com, C=US Reason: I am the author of this document Location: Date: 2023.08.02 14:32:37-08'00' Foxit PDF Editor Version: 12.1.2 Katherine O'Connor 323-438 DSR-8/4/23 X 10-407X 12/31/2024 Suspend VTL 8/17/2023 SFD 8/14/2023*&:JLC 10/3/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.10.03 11:25:35 -08'00' RBDMS JSB 100323 2P-419 Suspension Date Wrien: 17 July 2023 Execu on Date: August 21, 2023 Prepared by: Katherine O’Connor Background & Objecve KRU 2P-419 was an alternating gas or MI injector that has been shut in since March 2021. This well is ultimately slated to be P&Ad as part of the 2P pad abandonment. 2P pad does not have any facilities or surface line hookups, and the pad is slated to be used as storage for Willow development project in 2026. This well will be suspended in 2023, and it is currently planned to be fully abandoned in 2024. Well Data Reservoir pressure 1/24/2021 = 2912 RKB @ 5194’ TVD MASP = 2633 psi Last MITIA 8/16/2022 to 3590 psi (passed) Last tag 10290’ RKB on 10/5/2019 Has known parted liner at 10,290’ RKB Procedure Wireline & Pumping 1. Fluid pack tubing with KWF and freeze protect 2. Set CIBP @ ±10,200’ RKB (must be set within 50’ of the top of perforations) 3. Perform MIT-T to 2500 psi, record results 4. Dump bail at least 30’ of cement on top of CIBP 5. Allow 72 hours for cement to harden, notify AOGCC at least 24 hours in advance 6. RIH and tag TOC, approx. 10,170’ RKB (MUST BE AOGCC WITNESSED) 7. RU LRS as necessary. Perform pressure test to 1500 psi (MUST BE AOGCC WITNESSED) 8. Perform DDT and record results DHD 1. Schedule wellsite inspection within 12 months of suspension approval Last Tag Annotation Depth (ftKB) Wellbore End Date Last Mod By Last Tag: SLM 10,282.0 2P-419 4/22/2016 pproven Last Rev Reason Annotation Wellbore End Date Last Mod By Rev Reason: Pulled 2.81" Plug, Pulled DHSIT 2P-419 1/24/2021 fergusp Notes: General & Safety Annotation End Date Last Mod By NOTE: VIDEO LOG SHOWED PARTED LINER AT 10290' 2/14/2014 lehallf NOTE: View Schematic w/ Alaska Schematic9.0 8/8/2010 ninam Casing Strings Csg Des OD (in) ID (in) Top (ftKB) Set Depth (ftKB) Set Depth (TVD) (ftKB) Wt/Len (lb/ft) Grade Top Thread CONDUCTOR 16 15.06 29.0 108.0 108.0 62.50 H-40 WELDED SURFACE 9 5/8 8.83 28.1 3,286.9 2,351.6 40.00 L-80 BTC PRODUCTION 7 6.28 25.4 10,065.3 5,276.3 26.00 L-80 BTC-MOD LINER 3 1/2 2.99 9,893.0 10,943.0 5,669.7 9.20 L-80 SLHT Tubing Strings: string max indicates LONGEST segment of string Top (ftKB) 23.2 Set Depth … 9,946.1 Set Depth … 5,225.4 String Ma… 4 1/2 Tubing Description TUBING 4.5"x3.5" Wt (lb/ft) 12.60 Grade L-80 Top Connection IBT-MOD ID (in) 3.96 Completion Details: excludes tubing, pup, space out, thread, RKB... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 23.2 23.2 0.00 HANGER 10.800 GMC GEN V TUBING HANGER 4.500 504.8 504.4 5.32 NIPPLE 5.630 CAMCO 'DB' NIPLE W/3.875 NO GO PROFILE 3.875 9,776.5 5,152.8 64.98 GAS LIFT 5.984 CAMCO KBG-2-9 3.938 9,830.3 5,175.6 64.89 XO Reducing 5.200 CROSSOVER 4.5"x3.5" TUBING 2.991 9,879.1 5,196.4 64.45 SLEEVE 4.500 BAKER CMU SLIDING SLEEVE 2.812 9,895.1 5,203.3 64.30 NIPPLE 4.500 CAMCO 'D' NIPPLE w/2.75" NO GO PROFILE 2.750 9,908.2 5,209.0 64.30 LOCATOR 5.000 BAKER G-22 LOCATOR 3.000 9,909.4 5,209.6 64.30 SEAL ASSY 4.000 BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Mandrel Inserts : excludes pulled inserts Top (ftKB) Top (TVD) (ftKB) Top Incl (°) St ati on No /S Serv Valve Type Latch Type OD (in) TRO Run (psi) Run Date Com Make Model Port Size (in) 9,776.5 5,152.8 64.98 1 GAS LIFT DMY BK 1 0.0 11/5/2020 0.000 Liner Details: Excludes Liner, Pup, Joints, casing, float, sub, shoe... Top (ftKB) Top (TVD) (ftKB) Top Incl (°) Item Des OD Nominal (in)Com Make Model Nominal ID (in) 9,893.0 5,202.5 64.32 PACKER 7.000 BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,911.9 5,210.7 64.31 NIPPLE 5.500 RS PACKOFF SEAL NIPPLE 4.250 9,943.3 5,224.2 64.39 XO BUSHING 5.570 CROSSOVER BUSHING 3.000 Perforations & Slots Top (ftKB) Btm (ftKB) Top (TVD) (ftKB) Btm (TVD) (ftKB) Linked Zone Date Shot Dens (shots/ft)Type Com 10,216.0 10,236.0 5,339.4 5,347.8 T-3, 2P-419 3/1/2014 6.0 IPERF 2.5" GSPF HSD MILLENIUM, 60 deg phase 10,250.0 10,290.0 5,353.8 5,370.9 T-3, 2P-419 2/26/2014 6.0 IPERF 2" GSPF HSD MILLENIUM , 60 deg phase 10,510.0 10,530.0 5,466.7 5,475.6 T-3, 2P-419 3/8/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,530.0 10,570.0 5,475.6 5,493.5 T-3, 2P-419 3/7/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 10,644.0 10,664.0 5,527.3 5,536.6 T-3, 2P-419 3/6/2004 6.0 IPERF 2.5" HSD PJ, 60 deg phase 2P-419, 8/1/2023 5:33:51 PM Vertical schematic (actual) LINER; 9,893.1-10,943.0 IPERF; 10,644.0-10,664.0 IPERF; 10,530.0-10,570.0 IPERF; 10,510.0-10,530.0 IPERF; 10,250.0-10,290.0 IPERF; 10,216.0-10,236.0 PRODUCTION; 25.4-10,065.3 GAS LIFT; 9,776.5 SURFACE; 28.1-3,286.9 NIPPLE; 504.8 CONDUCTOR; 29.0-108.0 KUP INJ KB-Grd (ft) 35.30 RR Date 2/9/2004 Other Elev… 2P-419 ... TD Act Btm (ftKB) 10,945.0 Well Attributes Field Name MELTWATER Wellbore API/UWI 501032048300 Wellbore Status INJ Max Angle & MD Incl (°) 66.34 MD (ftKB) 6,182.71 WELLNAME WELLBORE2P-419 Annotation Last WO: End DateH2S (ppm) DateComment SSSV: NIPPLE 1 Regg, James B (OGC) From:Well Integrity Specialist CPF2 <n2549@conocophillips.com> Sent:Wednesday, August 17, 2022 10:00 AM To:Regg, James B (OGC); Wallace, Chris D (OGC); Brooks, Phoebe L (OGC); DOA AOGCC Prudhoe Bay Subject:CPAI 2P-Pad shut in tests 08-16-22.xlsx Attachments:MIT KRU 2P PAD SI TESTS 08-16-22.xlsx All Attached is the 10 426 form for the shut in tests performed on 2P pad on the 16 th of Aug 2022. Please let me know if you have any questions or concerns. Dusty Freeborn Well Integrity Specialist ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 Cell phone: (907) 830-9777 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Submit to: OPERATOR: FIELD /UNIT /PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2040170 Type Inj N Tubing 2605 2620 2610 2610 Type Test P Packer TVD 5209 BBL Pump 3.2 IA 470 3590 3500 3480 Interval V Test psi 2900 BBL Return 3.1 OA 203 360 310 290 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2011820 Type Inj N Tubing 827 827 828 828 Type Test P Packer TVD 5428 BBL Pump 1.0 IA 460 3210 3145 3130 Interval V Test psi 2900 BBL Return 0.9 OA 277 363 319 309 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2020180 Type Inj N Tubing 808 1001 980 953 Type Test P Packer TVD 5456 BBL Pump 2.3 IA 410 3200 3090 3075 Interval V Test psi 2900 BBL Return 2.0 OA 277 576 515 484 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2011020 Type Inj N Tubing 875 876 876 876 Type Test P Packer TVD 5219 BBL Pump 2.1 IA 390 3200 3110 3100 Interval V Test psi 2900 BBL Return 1.8 OA 236 569 539 531 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2020910 Type Inj N Tubing 1091 1091 1091 Type Test P Packer TVD 5177 BBL Pump 3.2 IA 450 3200 2105 Interval V Test psi 2900 BBL Return OA 278 405 345 Result F Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031530 Type Inj N Tubing 886 887 887 887 Type Test P Packer TVD 5141 BBL Pump 1.6 IA 470 3210 3110 3090 Interval V Test psi 2900 BBL Return 1.6 OA 254 356 321 312 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2010820 Type Inj N Tubing 112 288 298 294 Type Test P Packer TVD 5274 BBL Pump 1.7 IA 950 3210 3110 3100 Interval V Test psi 2900 BBL Return 1,6 OA 211 428 303 253 Result P Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 2031540 Type Inj N Tubing 882 882 882 882 Type Test P Packer TVD 5234 BBL Pump 2.0 IA 210 3210 3110 3110 Interval V Test psi 2900 BBL Return 1.8 OA 438 444 444 443 Result P TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes) 4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting 2P-438 2P-447 MITIA every 2 yr to max anticipated injection pressure per AIO 21C.002 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 2P-429 2P-432 2P-434 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 2P-427 Notes:MITIA every 2 yr to max anticipated injection pressure per AIO 21C.001 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 ConocoPhillips Alaska Inc, Kuparuk / KRU / 2P Pad Witness Waived by Guy Cook Beck / Borge 08/16/22 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 Tubing plug set at 8110' MD Notes: Notes:MITIA every 2 yr to max anticipated surface injection pressure per AIO 21C rule 4 2P-419 2P-420 Form 10-426 (Revised 01/2017)2022-0816_MIT_KRU_2P-pad_8wells 2P-419 MEMORANDUM TO: Jim Regg �e ,U [71 /412Ow P.I. Supervisor FROM: Guy Cook Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, August 6, 2020 SUBJECT: Mechanical Integrity Tests ConocoPhillips Alaska, Inc. 2P-419 KUPARUK RIV U MELT 2P-419 Src: Inspector Reviewed By: P.L Suprv�� Comm Well Name KUPARUK RIV U MELT 2P-419 API Well Number 50-103-20483-00-00 Inspector Name: Guy Cook Permit Number: 204-017-0 Inspection Date: 8/1/2020 Insp Num: mitGDC200803110452 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min - -- - Well 2P419- --- - -- - Type Inj I w- �TVD 5209 ,Tubing; 975 975- t000- l000' � 2oao17o Type Test - -- PTD SPT Test psi 2900 IA 50 3215 - 3100 - 3090 BBL Pumped: 4.7 BBL Returned: 4.4 OA 661 668 667 668 Interval REQVAR- - P/F P � ✓ Notes: MIT -IA every 2 years to max anticipated surface injection pressure per AIO 21C rule 4. Testing was completed with a Little Red Services pump truck and calibrated gauges. Thursday, August 6, 2020 Page 1 of I STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS r iri C� I +l5F`+ t1 vEx.., t.•,'7 1. Operations Abandon H Plug Perforations LJ Fracture Stimulate Ll Pull Tubing LJ Operations shutdown Ll Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: WAG Injection startup ❑� 2. Operator ConocoPhillips Alaska, Inc. 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ❑ Exploratory ❑ Stratigraphic ❑ Service ❑� 204-017 3. Address: P. O. Box 100360, Anchorage, Alaska 99510 6. API Number: 50-103-20483-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: Surface: ADL 373112/ BH: ADL 389058 KRU 2P-419 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): NA Ku aruk River Field/Meltwater Oil Pool 11. Present Well Condition Summary: Total Depth measured 10945 feet Plugs measured NA feet true vertical 5671 feet Junk measured NA feet Effective Depth measured 10,664' feel Packer measured 9909 feet true vertical 5,537' feet true vertical 5210 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 79' 16" 108' 108' Surface 3259' 9.625" 3287' 2352' Intermediate Production 10040' 10" 10065' 5276' Liner 1050' 3.5" 10943' 5670' Perforation depth Measured depth 10216-10664' feet True Vertical depth 5339-5537' feet Tubing (size, grade, measured and true vertical depth) 3.5" L-80 9946' 5225' Packers and SSSV (type, measured and true vertical depth) Baker 8040 GBH (Seal Assy) Seal Assy: MD = 9909', TVD = 5210' SSSV - 3.875" DB -LOCK W/ 4.5" CAMCO A-1 INJ VLV (0.086" BEAN) SSSV: MD= 505', TVD= 504' 12. Stimulation or cement squeeze summary: Intervals treated (measured): NA Treatment descriptions including volumes used and final pressure: NA 13, Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water-Bbi Casing Pressure Tubing Pressure Prior to well operation: 3500 01700 psi 2280 psi Subsequent to operation: 0 1000 1600 psi 966 psi 14. Attachments (required per 20 AAc 25.070, 25.071, s 25.283) 15, Well Class after work: Daily Report of Well Operations D Exploratory ❑ Development❑ Service Q Straligraphic ❑ Well Status after work: Oil ❑ Gas ❑ WDSPL ❑ Copies of Logs and Surveys Run F-116. Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑WINJ ❑ WAG [A GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 318-456 Authorized Name: Sayeed Abbas Contact Name: Sayeed Abbas Authorized Title: Staff Petroleum Engineercontact Email: saveed bbas anconocoghillips.com a 6 Authorized Signature: �+ ' 1� Date: 404 !1 J Contact Phone: 907-265-1109 Form 10-404 Revised 412017 k- 7-1— 9 q/JL//7 9 RBDMS edSEP 1 11019 Submit Original Only ConocoPhillips Alaska, Inc. 700 G St. Anchorage, AK 99501-3448 September 4th, 2019 AOGCC Commissioner State of Alaska, Oil & Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage, AK 99501 Dear Commissioner, ConocoPhillips Alaska, Inc. has completed changing the service of the Kuparuk River Unit (Meltwater) Well 213-419 from Gas Injection to Water Alternating Gas Injection. Enclosed you will find a 10-404 report of Sundry Well Operations for ConocoPhillips Alaska, Inc. If you have any questions regarding this matter, please contact me at 907-265-1109. Sincerely, Sayeed Abbas Staff Petroleum Engineer ConocoPhillips Alaska, Inc. Attachments: Report of Sundry Well Operations Daily report of Well Operations Well Schematic 2P-419 DAILY REPORT WELL OPERATIONS 8/23/2019: 2P-419 started water injection as part of the process to change the well from Gas Injection (GINJ) designation to Water -Alternating -Gas (WAG) designation KUP INJ 2P-419 ConocoPhdl)ps t Attributes Mn Angle 8 M0 ITO NOBka, Inc. wiDKIMW'M NEI A w.neon slnYa 501032048100 MELTWATER INJ nn 4n mDOlnel xl Blm (Mae) 68.31 6,182'11 10.905.0 LS$SV.NIPPLE MRS lma 1 -ma wo : nd M! KBL�a lnl RIq RYaw OW 35.30 2ro2004 717+14 aa5a0a tta6ei AY VenkYstxFT%atNe MMtlbnO I MnWWon Lit Me6 ey FnO Dfe _. _.. LaYTnram 10,2820 4(0/2016 RM Rm6on: TAG pgoren 426'2016 H7YGER.13i Casing rugs CONDUCTOlRlon DD pp mpIS Top IM1KSj ...'I sn Delxn lTVD)... Um 11. Hm NELCEa9 CONDUCTOR i6 15.062 29.0 108.0 100.0 82.50 MJO WELDED CWIgDmnglen OD pal ID (IM T.,MK81 Bn De9n(n6B1 an DePa, nWI... WULen I1... Gaea Teo Tm. 0 AT SURFACE 9618 &S35 28.1 3,285.9 2.351.6 40.001.K.:* umIn9 Dxcnplmn ODOn) ID(I.) Ta MKIR 6n Depu MRB1 6n Pa"lTvP,-wtlLen ll... cmae TeP Txmd PRODUCTION 7 8276 25,4 10,065.3 5,276.3 26.011 LW BTC -MOD wv R,,I Obaplbn 00(In) IDllnl am, Bal Oa{N IIKKa) Bal Ol pM ITYD)... en11..GMe Top Tnma6 LINER 31/2 2.992 9,893.0 10943.0 5.669.7 920 L 80 SLHT ,I. - Liner Details x mI, Tap TOP ITVD)InNBI TuPlnn l9 nam Dee C. n& 9.893.0 5.202.5 61.32 PACKER BAKER Z%P HR LINER TOP ISOLATION PACKER &OW 9,89 91911.9 5.210.7 64.31 NIPPLE AS RACKOFF SEAL NIPPLE 0.250 CONDUCTOR'2 bK$0 9,914.7 5.211.6 fi4.31 HANGER BAKER FLER-LUCK LINER HANGER 5000 9,924.7 5.2182 64.34 SBE BAKER MA"0 AL BORE EXTENSION 4.000 MNPLe5M4 9,913.3 5.224.2 64.39 XO BUSHING CROSSOVER BUSHING 3000 vuve Sa4e Tubing Strings nning Descdl+ion stnnq w_ m pnj rop @xel sn Dep+x M- sn Dapm (rvD) L. wr Onml moan Top Cannenlon 41/2 3.950 2J.2 9,94GJ 5,225.4 1260L -BO IBLMOD Completion Completion Details N mmn lD TOP Inns) TOP ITw11- Tep lnaItem PaseoRn) 23.2 23.2 00 HANGER GMC GEN VBING HANGER 4.500 ffT 0-W ID 504.8 554A 532 NIPPLE CASCO OR RIPPLE W13 875 NO GO PROFILE 3.875 sVxEncE Ja t3)Ye- 9830.3 51175.6 61.89 %O Reducing CROSSOVER 4519 S TUBING 2.991 _ 9ON1 ,1 4 6445 SLEEVE BAKER CMU SUDMG SIEUVE 2.812 _ 8, 1 P CAMCOVNIP LE w2.7'NOGOPROFRE 2.750 8,905.2 &2418.0 60.30 LOCATOR BAKER G-22LOCATOR 3000 4 1 9,909.4 5126.6 54.30 SEAL ASSY BAKER W40 CARS SEAL ASSEMBLY wMALF MULE 3000 SHOE Other In Hole (WIMURS retrbvable Pbgs, salees, PUMPS,11911, Mo.) Top W) Top lnnal (K ToPlnal 1°I Dee Cam Run DYe ID lip GASLiT 97765 501.8 5044 5.32 VALVE 3.B7YWLOCKW/4.5'CAMCOA-11NJVLV 1,2Sr014 3.875 (0.0313' BEAN, SER 9 HAGS 0551) 1 Perforations 8 Slots 961 lon ToP (TVD) BIM RmaovI TOPINKS) Bim IMaO) KS) MKS) IDne DM t) iAR Gam 10,218.0 t0,Z3&0 S3 5,338.4 5,3Q.8 F&217418 YV2014 8.0 MERF 25° PFSD M9IEMUM,W dp pxam MEe.B..9Y91 10250.0 10.2900 5.353.8 5,370.9 Td, 2P419 61162014 6.0 IPERF 2GSPF HAD MILLENIUM, 60ddg ,nage 1 i 1 6. FRF 2.6HS d deg Pxam NIPJLE:9A941� 10530.0 10,570.0 5.475.6 5,493.5 T S 2P419 39/ 6.0 IPERF M" H , 60 g pla e LOC.MO4eB0ai 10,844.0 t0. 0 .3 ,636. 18 .6'HSDPJJ30deg pxam Mandrel Inserts Y m NTep NVOI Top MKS) MKIR Yate NOMI NlLnM OD Rp Sam = Type Pon dxe TRO Run (In) ,= RYnOW Lam sEu nssr; s9w' 1 9,176. 5,1523 CARII. KBG-2- IJURSLIII OMY BK 0.000 0.0 611 W 9 I - Notes: General& Safety Fna DYe Annot . nYDD w/ BSc ma0c9. .1.1. NOTE: VIDEO LOG SHOWED PARTED LINER AT 1029(1' PRODUCTION:MAL]0.065.3� IPERF:10.2180103J00� amam.I0a00B10.isG0- IPENF; t0,5t00f03J00� m ERF;103300�t03700- IPERF:10.6a40t06N0- URFA 9,693tn0,5aJ0- MEMORANDUM • TO: Jim Regg � j P.I. Supervisor '&l `t `�( 771,0" FROM: Guy Cook Petroleum Inspector NON -CONFIDENTIAL 0 State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, August 20, 2018 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA, INC. 2P-419 KUPARUK RIV U MELT 2P419 Sre: Inspector Reviewed By: P.I. Supry :XP— Comm XPComm Well Name KUPARUK RIV U MELT 2P-419 API Well Number 50-103-20483-00-00 Inspector Name: Guy Cook SC��P�EQ Permit Number: 204-017-0 Inspection Date: 8/15/2018 - Insp Num: mitGDC180815155545 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2P-419 Type Inj G TVD 5209 Tubing 2675 2675 2675' 2675 - PTD 2040170 Type Test SPT Test psi j 2900 IA 1535 3500 3445 3435 BBL Pumped: 3.4 BBL Returned: 3 OA 320 - 330 330_-_330 Interval REQVAR P/F P ✓ _— — Notes: MITIA to max anticipated surface injection pressure per AIO 2 1 C rule 4. Little Red Services pump truck was used for testing. SEP 1 92018 Monday, August 20, 2018 Page 1 of 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: Monday,August 22,2016 P.I.Supervisor �`ZS 1 tC. SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-419 FROM: Brian Bixby KUPARUK RIV U MELT 2P-419 Petroleum Inspector Src: Inspector Reviewed By: p G+ P.I.Supry NON-CONFIDENTIAL Comm Well Name KUPARUK RIV U MELT 2P-419 API Well Number 50-103-20483-00-00 Inspector Name: Brian Bixby Permit Number: 204-017-0 Inspection Date: 8/20/2016 Insp Num: mitBDB160821042716 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2P-419 Type Inj G" TVD 5209 " Tubing 2650 - 2650 _ j 2650 - 2650 PTD 2040170 TYp e Test SPT Testpsi 2900 IA 1720 3280 - 3230 - 3220 '----- Interval REQVAR P/F P OA 128 - 131 131 131 Notes: A10-21B SCANNED MAY 1 A 7017 Monday,August 22,2016 Page 1 of 1 Wallace, Chris D (DOA) From: Regg,James B (DOA) Sent: Sunday, March 01, 2015 1:07 PM To: NSK Problem Well Supv;Wallace, Chris D (DOA) Cc: Senden, R.Tyler Subject: RE: Report of insufficient MIT test pressures 2P-419 (PTD 204-017) and 2P-447 (PTD 203-154, AIO 21A.006) 3-1-15 Attachments: 2P-419 90 day TIO 3-1-15.JPG; 2P-447 90 day TIO 3-1-15.JPG Understand the time to clean up due to last night's storm. I don't think a retest is necessary. More important is how this happened -the initial test was done to the required pressure so why not the subsequent test? CPAI's new WellTrak system should have prevented this. Jim Regg Supervisor, Inspections AOGCC 907-793-1236 Sent from Samsung Mobile SCANNED j, ; FT 4 Original message From: NSK Problem Well Supv<n1617@conocophillips.com> Date: 03/01/2015 11:18 AM (GMT-09:00) To: "Regg, James B (DOA)" <jim.regg@alaska.gov>,"Wallace, Chris D (DOA)" <chris.wallace@alaska.gov> Cc: "Senden, R. Tyler" <R.Tyler.Senden@conocophillips.com> Subject: Report of insufficient MIT test pressures 2P-419 (PTD 204-017) and 2P-447 (PTD 203-154, AIO 21A.006) 3-1-15 Jim, Chris, During a routine audit, it was identified that 2 gas injectors at Meltwater, namely 2P-419 (PTD 204-017) and 2P-447 (PTD 203-154 AIO 21A.006) recently had witnessed MITs performed to insufficient test pressures. Per AIO 21A,the MITs need to be performed to the maximum anticipated injection pressure. Both wells were shut-in at the time of the 2 yr pad testing in August 2014 and had witnessed MITs performed at that time. These tests were appropriately performed to the anticipated injection pressure (see attached MITs for reference). After returning to injection on 12-11-14, 2P-419 and 2P-447 were tested on 12-26-14 after reaching stabilization. However those tests pressures were insufficient to meet the requirements of Meltwater's Area Injection Order. It is CPAI's intention to keep the wells online and to schedule witnessed retests ASAP. However, if you believe it is appropriate, we can shut in the wells. Of note, an intense Phase 3 storm came in last night and it is expected to take many days of cleanup. Therefore it will probably be several days before we will be able to schedule the tests. Please let us know if you disagree with the plan. Well Name 2P-419 Notes: Start Date 12/1/2014 Days 90 End Date 3/1/2015 Annular Communication Surveillance 4&00 — 1LC WHP IAF 3E0C OAP b'JHT — 12C 3000 inga - — 100 2E0C — 80 'ta 2000 C. — c0 1EOC - LO 1000 SOC — 20 0 0 Nov-14 Nov-14 Dec-14 Dec-14 Dec-14 Jan-15 Jan-15 Jan-1E Feb-1E Feb-1E Feb-15 Mar-15 1 • JAI x d •m FP/ 14'°°"°°7-'J KC Sep-14 Dec-14 Mar-15 Date 2 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission To Jim Regg DATE: Friday,January 09,2015 P. Supervisor ke ��IS f �� SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-419 FROM: John Crisp KUPARUK RIV U MELT 2P-419 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry J • NON-CONFIDENTIAL Comm Well Name KUPARUK RIV U MELT 2P-419 API Well Number 50-103-20483-00-00 Inspector Name: John Crisp Permit Number: 204-017-0 Inspection Date: 12/26/2014 Insp Num: mitJCr141231121836 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 2P-419 'Type Inj G 1TVD 5209 - Tubing 2690 2690= 2690 _ 2690 - i — — — PTDI- 2040170 (Type Test SPT Test psi 1500 IA 1612 2203 - 2158 - 2154 - Interval1oTHER P/F P -I OA 220 266 • 254 249 Notes: 1.1 bbl pumped for test 2 year as per AIO 21A , SCANNED • Friday,January 09,2015 Page 1 of 1 e e Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Q. .0 J¡..- 0 1 7 Well History File Identifier D Two-sided 11111111111" 111111 Production Scanning Stage 1 Page Count from Scanned File: ~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES BY: ~ Date: '+1' 10 Þ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES Organizing (done) RESCAN ~olor Items: D Greyscale Items: DIGITAL DATA D Diskettes, No. D Other, NofType: D Poor Quality Originals: D Other: NOTES: Date 1./-/ ~/ 0 ~ Datel/:j(p! O(P &0 BY: ~ Project Proofing BY: ~ Scanning Preparation BY: Date: BY: Maria Date: Scanning is complete at this point unless rescanning is required. D Rescan Needed 1111111111111111111 OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) D Logs of various kinds: D Other:: tl1P 11111111I111111111I /5/ /5/ MP 1/111111I1111111111 NO /51 vvtP NO 15/ 11111111I11I1111111 ReScanned BY: Maria Date: 15/ Comments about this file: 11111111111111 111I1 Quality Checked 1111111111/11111111 10/6/2005 Well History File Cover Page.doc �, OF T$ • • ,,"\\\ / THE STATE ....„ �j�s,), and Gas __ . censervation Commission -TR,, -, GOVERNOR SEAN PARNELL 333 West Seventh Avenue O''4LA54� Anchorage, Alaska 99501-3572 Main: 907.279.1 433 �'®� L1': Fax: 907.276.7542 �"'tkED its J'.;_ . l' 1 a •Thomas Nenahlo Drillsite Petroleum Engineer ConocoPhillips Alaska, Inc. aag-- 017 P.O. Box 100360 Anchorage, AK 99510 Re: Kuparuk River Field, Meltwater Oil Pool, 2P-419 Sundry Number: 313-564 Dear Mr. Nenahlo: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 41/ Cathy P. oerster Chair, Commissioner DATED this day of November, 2013. Encl. RECEIVED STATE OF ALASKA %, 1111SKA OIL AND GAS CONSERVATION COMMIOIN 1 ik A$ OCT 2 5 2013 APPLICATION FOR SUNDRY APPROVALS \V 20 AAC 25.280 AOGCC 1.Type of Request: Abandon r Plug for Redrill r Perforate New Pool r Repair w ell r Change Approved Program r Suspend r Rug Perforations r Perforate r Pull Tubing r Time Extension r Operational Shutdown r Re-enter Susp.Well r Stimulate r Alter casing r Other:Logging l✓. 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: ConocoPhillips Alaska,Inc. Exploratory r Development r 204-017 3.Address: Stratigraphic r Service I✓ 6.API Number: P.O.Box 100360,Anchorage,Alaska 99510 50-103-20483-00 7.If perforating, What 8.Well Name and Number: Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require spacing exception? Yes r No r 2P-419 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL03731121ADL0389058 Kuparuk River Field/Meltwater Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 10945 5671 Casing Length Size MD TVD Burst Collapse CONDUCTOR 79 16 108' 108' SURFACE 3259 9 5/8 3287' 2352' PRODUCTION 10040 7 10065' 5276' LINER 1050 31/2 10943' 5670' Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 10216-10236, 10250-10290, 10510- 5339-5348,5354-5371,5467-5476,5476- 10530, 10530-10570, 10644-10644 '5494,5527-5537 4.5"/3.5" L-80 9946 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft) SEAL ASSY-BAKER 80-40 GBH-22 SEAL ASSEMBLY W/HALF MULE SHOE MD=9909 ND=5210 12.Attachments: Description Summary of Proposal 17 13. Well Class after proposed work: Detailed Operations Program BOP Sketch r Exploratory r Stratigraphic r Development r Service ./ 14.Estimated Date for Commencing Operations: 15. Well Status after proposed work: 2/1/2014 Oil r Gas r WDSPL r Suspended r 16.Verbal A Approval: Date: Abandoned r pp WINJ r GINJ WAG r Commission Representative: GSTOR r SPLUG r 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Tommy Nenahlo Email: Thomas.L.Nenahlo(cr�,cop.com Printed Name Thomas Nenahlo Title: Drillsite Petroleum Engineer Signature r 7. e9 3----- Phone:265-6934 Date:10/25/2013 Commission Use Only Sundry Number: Conditions of approval: Notify Commission so that a representative may witness \''S— S(Q 14 Plug Integrity r BOP Test r Mechanical Integrity Test r Location Clearance r RBA MS NOV 1 5 20 Other: RBDMS NIA ilo °perm j,, in 4cc nce e-vA A-(O2IA.003 ,,,fff Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: / ) 4.17 t� ,/- APPROVED BY Q ' /� Approved by: `L- COMMISSIONER THE COMMISSION Date://'" O Approved ap lication is valid for 12 months from the date of approval. Form 10-403(Revised 10/2012) 0 ' GINN_ 01)4../ 10/31/01 3 Submit Form and Attachments in Duplicate VLF ii/6' /03 • • t.r OCT 17 2013 ConocoPhillips AOGCC Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 October 17th, 2013 Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 SUBJECT: Requests for Administrative and Sundry Approvals for Meltwater Surveillance Initiatives Dear Mr. Wallace: As discussed in the meeting held on September 26th, 2013, between the Alaska Oil and Gas Conservation Commission(AOGCC) and ConocoPhillips Alaska, Inc. (CPAI), the Meltwater team is pursuing a number of surveillance initiatives to aid in the characterization and understanding of the Meltwater shallow gas issue while collecting further data for the evaluation of development options. Attached within this communication are the technical justifications for the necessary administrative and sundry approvals to achieve the objectives of these surveillance initiatives. The surveillance initiatives that are currently being pursued are as follows: • An extended outer annulus bleed at well 2P-431 o Pertaining to this initiative, please find a request for Administrative Approval via Rule 10, Area Injection Order 21A (Amended), for Meltwater production well 2P-431 (PTD 202-053) in regard to Rule 3 (annular pressure limits). Also enclosed is an Application for Sundry Approval (10-403) for authorizing annular flow from 2P-431. • Video and Spectra-Flow®logging at wells 2P-419, 2P-420, 2P-427, 2P-429, 2P- 434, 2P-447 o Pertaining to this initiative,please find a request for Administrative Approval via Rule 10, Area Injection Order 21A(Amended), for Meltwater injection wells 2P-419 (PTD#204-017), 2P-420 (PTD# 201- 182), 2P-427 (PTD# 202-018), 2P-429 (PTD#201-102), 2P-434 (PTD# 203-153), 2P-447 (PTD# 203-154) in regards to Rule 7 (authorized injection pressure) and Rule 8 (authorized fluids for injection). Please call Tommy Nenahlo at 265-6934, or me at 265-1464 if you have any questions. • S ConocoPhillips INV Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 Sincerely, Jerry Dethlefs ConocoPhillips Well Integrity Director Tommy Nenahlo ConocoPhillips Meltwater Drill Site Petroleum Engineer Enclosures: Technical Justification for Administrative Relief Requests Application for Sundry Approval Wellbore Schematic • • ConocoPhillips Alaska,Inc. Kuparuk River Unit Meltwater Pool Injection Wells Technical Justification for Administrative Relief Request,AIO 21A,from Rules 7 and 8 Purpose ConocoPhillips Alaska, Inc. (CPAI)requests that the AOGCC approve this Administrative Relief as per Area Injection Order(AIO)21A(Amended),Rule 10,for temporary relief from criteria set forth in Rules 7 and 8 that defines the authorized pressure and fluids for injection,respectively. CPAI requests temporary relief from these rules to conduct video and Spectra Flow®logging on six Meltwater injectors, 2P-419(PTD#204-017),2P-420 (PTD#201-182),2P-427(PTD#202-018),2P-429(PTD#201-102), 2P- 434(PTD#203-153), and 2P-447(PTD#203-154). By conducting video logging on these injectors,the Meltwater team is looking to inspect possible collapsed liner, as has been indicated by recent and historic well work. By conducting Spectra Flow® logging,the Meltwater team is looking to determine if there is fluid movement around the production casing cement shoe over a range of sand face injection pressures. Video Logging Campaign Summary During recent and historic well work, indications of potentially collapsed liner in injectors 2P-419,2P- 420, 2P-429,2P-434, and 2P-447 have arisen. In a number of these injectors it is believed that these potential collapsed liner locations are limiting our injection into the Bermuda formation. To aid in characterizing and understanding these potential collapsed liner locations, as well as to formulate a plan to remediate this issue, it is necessary to run video logs to inspect the locations. To safely execute a video log on a miscible injectant(MI)injector it is necessary to adequately displace the near wellbore formation to ensure that MI returns are not taken to surface. Therefore, it is recommended that the near wellbore formation be displaced with a minimum three tubing volumes of hot diesel. Upon adequately displacing the near wellbore formation,the video log will be run while injecting filtered sea water to allow for the optimum video resolution to inspect these potential collapsed liner locations. The ability to provide a sufficient injection rate at Meltwater is critical as it is necessary to ensure that adequate lift gas temperatures are maintained at the Meltwater's Drill Site, 2P. Drill Site 2P is located approximately twelve miles from the nearest drill site,2N. This distance provides a significant amount of time for cooling of the MI that is used as injection fluid as well as a lift gas for the producers. During winter months and low injection rate periods,the temperature of the lift gas has historically become low enough to cause rapid paraffin deposition in the upper wellbore of the producers and can choke flow to a point at which the well would need to be shut in. If enough production is shut in the temperature of the Meltwater produced oil line could become low enough to require it to be shut in and de-inventoried to mitigate the potential for the line to freeze. In 2012,modeling was completed to determine the minimum MI gas delivery temperature at Meltwater to ensure that this issue can be mitigated. As anticipated,the variable with the greatest effect on the MI gas delivery temperature at Meltwater is the MI injection rate. By completing video logs on these potential collapsed liner locations to aid in developing a remediation strategy it is believed that this risk of low lift gas temperature and a produced oil line freezing scenario can be reduced. To successfully complete this video logging campaign,temporary relief from AIO 21A(Amended) Rules 7 and 8 is requested to adequately displace the formation and conduct these video logs. CPAI Well Integrity Director 10/172013 • • Spectra Flow®Logging Campaign Summary To successfully complete this Spectra Flow®logging campaign,temporary relief from AIO 21A (Amended)Rule 8 is requested to allow for the temporary injection of sea water into the Bermuda formation. Sea water is not an authorized injection fluid in AIO 21A(Amended). The Halliburton®Spectra-Flow logging technology is capable of identifying fluid movement around the production casing shoe by identifying the presence of oxygen. Sea water will provide the oxygen in the injection fluid to ensure the logging campaign can be completed successfully. To achieve the most information from the logging campaign,temporary relief from AIO 21A(Amended) Rule 7 is requested for exceeding the established pressure limit during injection of sea water into the Bermuda formation while logging. The Meltwater team would like to vary the injection pressures of the sea water while performing Spectra Flow®logging runs to complete the following objectives: 1. To confirm there is not fluid movement around the production casing shoe when injecting within the sand face injection pressure limit established by Rule 7 in AIO 21A(Amended). 2. To determine if MI migration is a result of historic sand face injection pressures at Meltwater prior to the issuance of AIO 21A(Amended). The second objective stated above is intended to further the Meltwater team's understanding of the MI migration mechanism. As discussed in the November 2012 hearing with the AOGCC,the Meltwater team proposed two potential MI migration mechanisms. One of these migration mechanisms includes the possibility of MI migration around the production casing cement shoe. By completing the aforementioned objectives,the Meltwater team will be able to make more informed decisions to ensure the field is operated safely and effectively. Video and Spectra Flow®Logging Procedure Outline The following is an outline of the procedure for the proposed Spectra Flow®Logging campaign to be performed on each of the six injectors. 1. Displace the near wellbore formation with a minimum three tubing volumes of hot diesel to mitigate the risk of taking MI returns at surface during well work operations. o Injection pressure at surface not to exceed 2,495 psig with diesel (4475 psig at perf depth assuming 0.36 psi/ft gradient and 5,500 ft TVD to mid-perfs) 2. Rig up E-Line with Spectra-Flow®Logging tools and IPROF string to monitor bottomhole conditions. 3. Little Red Services(LRS)to pump sea water down on well using a step rate approach as defined below. During each step,the Spectra-Flow®logging tool will be passed up and down to identify the possible height of injected fluid above the perforations. a. Step 1: 500 psi WHIP (2975 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) b. Step 2: 750 psi WHIP(3225 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) c. Step 3: 1,000 psi WHIP(3475 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs)\ d. Step 4: 1,250 psi WHIP(3725 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) e. Step 5: 1,500 psi WHIP (3975 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) CPAI Well Integrity Director 10/17/2013 2 • • f. Step 6: 1,750 psi WHIP(4225 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) g. Step 7: 2,000 psi WHIP(4475 psi at perf depth assuming 0.45 psi/ft gradient and 5,500 ft TVD to mid-perfs) 4. Upon completion of the step rate logging runs,E-Line and LRS will rig down and move off the well. 5. Injection of seawater will cease on each individual well after the logging runs are completed. 6. The well bores will then be freeze protected with the injection of hot diesel with the injection pressure at surface not to exceed 2,495 psig(4475 psig at perf depth assuming 0.36 psi/ft gradient and 5,500 ft TVD to mid-perfs) Administrative Approval Request: CPAI requests temporary relief from(AIO)21A(Amended),Rules 7 and 8 to conduct Video and Spectra Flow®logging on six Meltwater injectors: 2P-419(PTD#204-017), 2P-420(PTD#201-182), 2P-427(PTD#202-018), 2P-429(PTD#201-102), 2P-434(PTD#203-153), 2P-447(PTD#203-154). 1. Temporary relief from AIO 21A(Amended)Rule 7 is requested for exceeding the pressure limit during injection of sea water into the Bermuda formation during the logging operations only. The approval is requested for a period of six months from the date of the AOGCC approval. 2. Temporary relief from AIO 21A(Amended)Rule 8 is requested to allow for injection of sea water into the Bermuda formation for the purposes of performing the logging operations only. The approval is requested for a period of six months from the date of the AOGCC approval. CPAI Well Integrity Director 10/17/2013 3 S • ConocoPh i I l i ps Alaska P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 October 25th, 2013 Chris Wallace Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Response to Questions Regarding Requests for Administrative and Sundry Approvals for Meltwater Surveillance Initiatives Dear Mr. Wallace: Thank you for your reply regarding our requests for Administrative and Sundry Approvals for the Meltwater surveillance initiatives. Please find below the responses to your questions in your emails that were sent October 22"d, 2013. Injected Volumes and Duration Per the plan developed by the Meltwater team, it is expected that no more than 6,000 barrels of Beaufort seawater will be required to be injected at each injector to complete the video and Spectra-Flow®logging initiatives. This estimate of 6,000 total barrels includes the procedures to complete the miscible injectant displacement, video logging, and Spectra-Flow®logging procedures. Below is a high level breakdown of this estimate for clarity: • Displacement volume estimate: 1,000 BBLs of seawater per well o This is volume that we may need during the video and/or Spectra-Flow®logging campaign to mitigate the potential for having miscible injectant present in the wellbore. • Video Logging volume estimate: 1,600 BBLs of seawater per well o To minimize the turbidity of the fluid, and thus increase our video resolution at the potential collapsed liner locations, filtered seawater will be used to displace the wellbore and ensure it remains displaced throughout the video logging procedure. • Spectra-Flow®Logging volume estimate: 3,400 BBLs of seawater per well o This estimated volume of 3,400 BBLs is planned to be split evenly amongst the seven pressure stages outlined in the Technical Justification for Administrative Relief Request, AIO 21A(Amended), from Rules 7 and 8, that was submitted to the AOGCC on October 17th, 2013. o It is preferred that seawater be used for the Spectra-Flow®logging as upright tanks will be on location at Drill Site 2P to store the seawater that will support the aforementioned video logging. Operationally, it is preferred that Kuparuk produced water be kept separated from seawater due to corrosion concerns. The above logging initiatives may require up to 168 hours (7 days) to complete, per well. • • ConocoPhillips Alamo P.O. BOX 100360 ANCHORAGE,ALASKA 99510-0360 Beaufort Seawater Compatibility Study A Meltwater field fluid sensitivity and stimulation study was completed in March of 2001. This study utilized core samples from the Meltwater North#1 and Meltwater North#2 wells that included an investigation into the sensitivity of preserved reservoir samples to the proposed flood waters. These proposed flood waters included a Kuparuk produced water blend and a 75% Kuparuk produced water/25% Beaufort seawater blend. The investigation into the sensitivity of the Meltwater North#1 and Meltwater North#2 core samples to the proposed flood waters concluded that there were no adverse reactions to the75% Kuparuk produced water/25% Beaufort seawater blend identified. The Meltwater team plans to inject 100% Beaufort seawater to minimize the turbidity of the fluid while conducting video logging. Although we do not have fluid sensitivity studies completed with 100% Beaufort seawater, the salinities of the Kuparuk produced water and the Beaufort seawater are similar, and no appreciable compatibility problems for either the Meltwater formation or its confining zones are expected. If injectors do incur damage from sea water injection the damage will be contained within a small radius of the wellbore due to the small volume of fluid required to complete the logging initiatives. Any damage to the near wellbore formation that may arise can be reversed by employing remedial treatments. Sundry Requests Attached you will find six Application for Sundry Approvals, one for each of the six wells that we are requesting approval to conduct video and Spectra-Flow®logging. If you require any further information, please do not hesitate, I would be more than happy to address them for you. Thanks, 7;~If&e i /D Tommy Nenahlo Drill Site Petroleum Engineer 2T (Kuparuk&Tabasco) &2P (Meltwater) North Slope Operations& Development ConocoPhillips Alaska Anchorage: (907)265-6934 Mobile: (720)273-2685 Enclosures: Applications for Sundry Approval (Quantity 6) Wellbore Schematics (Quantity 6) j . ! KUP 2P-419 Conoc 1Philli LWell Attributes Max Angle&MD TD Alaska,Inc. Wellbore API/UWI Field Name Well Status Inc!(°) I MD(ftKB) Act Btm(ftKB) Concxoehmeps I 501032048300 MELTWATER INJ 66.34 6,182.71 10,945.0 Comment H2S(ppm) Date Annotation End Date KB-Grd(ft) Rig Release Date "' SSSV:NIPPLE Last WO: 35.30 2/9/2004 Well Conhq:-2P-419,6/3/2013 2•28:24 PM Schematic-Actual Annotation Depth(ftKB) I End Date Annotation Last Mod... End Date Last Tag:SLM 10,285.0 5/28/2013 Rev Reason:TAG haggea 6/3/2013 Casing Strings UN Casing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(ND)... String Wt... String... String Top Thrd HANGER,23 - CONDUCTOR 16 15.062 29.0 108.0 108.0 62.50 H-40 WELDED pp Casing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd SURFACE 9 5/8 8.835 28.1 3,286.9 2,351.5 40.00 L-80 BTC Casing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd PRODUCTION 7 6.276 25.4 10,065.3 5,276.3 26.00 L-80 BTC-MOD Casing Description String 0... 'String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)... String Wt... String... String Top Thrd �' LINER 3 1/2 2.992 19,893.1 I 10,943.0 5,669.7 9 20 L-80 SLHT Liner Details A .. .� ...=,,, ma». .�...t ..,.4., �.x , ia,. Top Depth (ND) Top Inc! Nomi... Top(ftKB) (ftKB) (1 Item Description Comment ID(in) 9,893.1 5,202.5 64.32 PACKER BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9,912.0 5,209.8 63.75 NIPPLE RS PACKOFF SEAL NIPPLE 4.250 CONDUCTOR, 9,914.7 5,211.1 63.78 HANGER BAKER FLEX-LOCK LINER HANGER 5.000 29-108 9,924.7 5,215.6 63.87 SBE BAKER 80-40 SEAL BORE EXTENSION 4.000 NE 9,943.3 5,223.9 64.05 XO BUSHING CROSSOVER BUSHING 3.000 NIPPLE,505 HE Tubing Strings lir° Tubing Description String 0... String ID... Top(ftKB) Set Depth(f... Set Depth(TVD)...!String Wt...I String...'String Top Thrd ,' TUBING 4.5"x3.5" 41/2 I 3.958 23.2 9,946.1 5,225.2 12.60 1 L-80 IBT-MOD Completion Details _, Top Depth (TVD) Top Inc! Nomi... Top(ftKB) (ftKB) (°) item Description Comment ID(in) ', 23.2 23.2 -1.41 HANGER GMC GEN V TUBING HANGER 4.500 504.8 504.3 5.99 NIPPLE CAMCO'DB'NIPLE W/3.875 NO GO PROFILE 3.875 9,830.3 5,175.6 64.89 XO Reducing CROSSOVER 4.5"x3.5"TUBING 2.991 SURFACE, . • 28-3,287 „ 9,879.1 5,196.5 64.45 SLEEVE BAKER CMU SLIDING SLEEVE 2.812 '€ 9,895.1 5,203.3 64.30 NIPPLE CAMCO D'NIPPLE w/2.75"NO GO PROFILE 2.750 Mk 9,908.2 5,208.1 63.71 LOCATOR BAKER G-22 LOCATOR 3.000 9,909.4 5,208.7 63.73 SEAL ASSY BAKER 80-40 GBH-22 SEAL ASSEMBLY w/HALF MULE SHOE 3.000 Perforations&Slots Shot Top(ND) Btm(ND) Dens Top(ftKB) Btm(ftKB) (ftKB) (ftKB) Zone Date (sh••• Type Comment GAS LIFT, 10,216.0 10,236.0 5,339.4 5,347.9 T-3,2P-419 3/9/2004 6.0 IPERF 2.5"HSD PJ,60 deg phase 9,776 111C -' 10,250.0 10,290.0 5,353.8 5,371.3 T-3,2P-419 2/8/2004 6.0 IPERF 2.5"HSD PJ,60 deg phase al 10,510.0 10,530.0 5,467.0 5,475.7 T-3,2P-419 3/8/2004 6.0 1PERF 2.5"HSD PJ,60 deg phase III III 10,530.0 10,570.0 5,475.7 5,493.5 T-3,2P-419 3/7/2004 6.0 IPERF 2.5"HSD PJ,60 deg phase 10,644.0 10,664.0 5,527.3 5,536.7 T-3,2P-419 3/6/2004 6.0 IPERF 2.5"HSD PJ,60 deg phase Notes: General&Safety ,. � � End Date Annotation ..--....... 8/8/2010 NOTE:View Schematic w/Alaska Schematic9.0 SLEEVE,9,879 NIPPLE,9,895 ir- LOCATOR, r?w5" 9,908 la __--a , 1 SEAL ASSY, __. . 9,909 S. PRODUCTION, .A I. 25-10,065 IPERF, _--_-• 10,216.10,236 � ,.�sw. 3 .' era- IPERF, -: -= Mandrel Details ,,.., .��_• ,°i,v,e ate,:.; - 10,250-10,290 Top Depth Top Port - (ND) Ind OD Valve Latch Size TRO Run N... Top(ftKB) (ftKB) (°) Make Model (in) Sery Type Type (in) (psi) Run Date Com... IPERF, 10,510-10,530 1 9,776.5 5,153.0 65.38 CAMCO KBG-2-9 1 GAS LIFT DMY BK 0.000 0.0 5/16/2007 ---_ IPERF, 10,530-10,570 IPERF, -- -_ 10,644-10,664 - - LINER, 9,893-10,943 TD,10,945 Hunt, Jennifer L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, June 26, 2013 12:39 PM To: NSK Fieldwide Operations Supt Cc: Hunt, Jennifer L (DOA) Subject: RE: Meltwater SSSV Testing I missed that one... thanks.Transposed with 2P-419 PTD too. Here is updated corrected wells and PTD's. So a total of six wells. Well PTD 2P-447 203-154 2P-419 204-017 2P-434 203-153 2P-427 202-018 2P-420 201-182 2P-429 201-102 31•M4 aED FEB 2 ZO Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: NSK Fieldwide Operations Supt [mailto:NSKFieldwideOperationsSupt @@conocophillips.com] Sent: Wednesday, June 26, 2013 12:30 PM To: Schwartz, Guy L (DOA) Subject: RE: Meltwater SSSV Testing Guy, We also have well 2P-447 as a WAG injector. I don't have the PTD number handy, but I do have the API number— 501032046800. Thanks, Larry Larry Baker/Glynn Jones NSK Fieldwide Operations Superintendent N2072(�ConocoPhillips.com 907-659-7042 Pager 659-7000 x604 From: Schwartz, Guy L(DOA) [mailto:guy.schwartz©alaska.gov] Sent: Wednesday, June 26, 2013 10:59 AM To: NSK Fieldwide Operations Supt Cc: Regg, James B (DOA); Ferguson, Victoria L (DOA); Hunt, Jennifer L (DOA) Subject: [EXTERNAL]RE: Meltwater SSSV Testing Larry, 1 After further discussion and thought it would be best to reclassify the WAG injection wells on the Meltwater pad to GINJ (gas injector). The wells should be included in the upcoming SVS testing to be done in July. At some point in future if water is again available for injection on Meltwater the status can be reverted back to WAGIN. The wells in our database that need to have status changed from WAGIN to GINJ are: Well PTD 2P-419 203-154 2P-434 203-153 2P-427 202-018 2P-420 201-182 2P-429 201-102 We will change status in our database today... II Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: NSK Fieldwide Operations Supt [mailto:NSKFieldwideODerationsSuptCa�conocophillips.com] Sent: Tuesday, June 25, 2013 4:35 PM To: Schwartz, Guy L (DOA) Subject: Meltwater SSSV Testing Guy, We talked several months ago about the well classification status of the Meltwater(DS-2P) inJecto r s and w hethe r they should remain as WAG injectors or if we should change the well classification to GINJ. At that time you replied that it was your preference to leave the well as a WAG well status even though it will stay on MI for an indefinite period. We are going to perform the SVS testing for DS-2P in July and I just wanted to verify that you still wanted the well classification to remain as WAG. Please confirm that DS-2P should remain classified as a WAG injector. As a SSSV test is not required for a WAG injector, we also ask you to please confirm that we are not required to perform a SSSV test or report SSSV testing for DS-2P during the July pad SVS testing. I look forward to hearing back from you soon. Please feel free call me 659-7042 y to ca eat 659 7042 if you have any questions. Thanks, Larry Larry Baker/Glynn Jones NSK Fieldwide Operations Superintendent N2072ConocoPhillips.com 907-659-7042 Pager 659-7000 x604 2 Hunt, Jennifer L (DOA) From: Schwartz, Guy L (DOA) Sent: Wednesday, June 26, 2013 11:26 AM To: Hunt, Jennifer L (DOA) Subject: meltwater wells status change WAGIN to GINJ Put this in comments for 5 Meltwater wells: Well status change to GINJ: No injection water available on Meltwater pad for foreseeable future. Well needs to have SSSV tested every 6 months. Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office 1 MEMORANDUM To: Jim Regg {~ ,,,,)) P.I. Supervisor ~~t~ v~i'l~D FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commissimi DATE: Tuesday, August 10, 2010 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-419 KUPARUK RIV U MELT 2P-419 Src: Inspector NON-CONFIDENTIAL Reviewed By~ P.I. Suprv r ~ Comm Well Name: KUPARUK RIV U MELT 2P-419 Insp Num: mitRCN100809171157 Rel Insp Num: API Well Number: 50-103-20483-00-00 Permit Number: 204-017-0 Inspector Name: Bob Noble Inspection Date: 8/8/2010 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ~ 2P-419 ~ Type Inj. C* ' TVD 5209 ~ ~ IA 2716 3300 ~ 3260 3260 ' P.T.D 2040170 ~ TypeTCSt SPT Test pSl 3300 ~ QA 291 335 338 336 InterVal4YRTST per, P Tubing 3700 3700 3700 3700 Notes: J.,l i ~ . (\~~ d ~efr I ~CD~ at r. +, ~; {' to r l{ ,t„ Tuesday, August 10, 2010 Page I of ] • • -N.~=__ MICROFILMED 03/01 /2008 DO NOT PLACE .o,` .; ~ ~"~° °~` .,. ~~ ANY NEW MATERIAL UNDER THIS PAGE F:1LaserFiche\CvrPgs_Inserts\Microfilm Marker.doc MEMORANDUM . State of Alaska _ Alaska Oil and Gas Conservation Commis:!l" TO: Jim Regg .'\< !2¿,c c¡j( 'sO(<'Ãe P.I. Supervisor (r DATE: Wednesday, August 30, 2006 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-419 KUPARUK RIV U MELT 2P-419 Src: Inspector ,,0 \1 ~o~ FROM: Jeff Jones Petroleum Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv:Jï3.e-- Comm Well Name: KUPARUK RIV U MELT 2P-419 API Well Number 50-103-20483-00-00 Inspector Name: Jeff Jones Insp Num: mitlJ060829130325 Permit Number: 204-017-0 Inspection Date: 8/18/2006 Rei Insp N um Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 2P-419 Type Inj. w TVD 5202 IA 1030 1730 1730 1720 P.T. 2040170 TypeTest SPT Test psi 1500 OA 310 380 355 340 Interval 4YRTST P/F P // Tubing 2275 2275 2275 2275 Notes 0.5 BBLS diesel pumped. 1 well house inspected; no exceptions noted. SCANNED SEP 0 8200S Wednesday, August 30, 2006 Page 1 ofl .~ Conoc~hillips Alaska F{E 1""''' ~ ~ jUL 0 5 Z006 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 & G;j3 ~~cmmi5s~at1 jaJ1chorage June 06, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 (;;.r./B,.ŸlJN' -í:fj BUt 0 7' 2005 ~B"U1J~ å;F-"? Vb... ~ 'lP4- () '7 Dear Mr. Maunder: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor by surface casing annulus. The voids that were greater than 6 feet were first filled with cement to a level of2.5 feet. The remaining volume, 2.5 to 6 feet of annular void respectively was coated with a corrosion inhibiter, RG2401, then filled with a viscous hydrocarbon based sealant, Royfill404B, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The cement top-fill operation was completed on May 05,2006. Schlumberger Well Services mixed 15.7 ppg Arcticset I in a blender tub. The cement was pumped into the conductor bottom and cemented up via a hose run to the existing top of cement. The corrosion inhibitor and sealant were pumped in a similar manner on May 18th, 19th and 31 st, 2006. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call Marie McConnell or myself at 907-659-7224, if you have any questions. ~ ::lio Perry Klein ConocoPhillips Problem Well Supervisor {""(..-sv-J d~ 06!~ù/()6 Attachment -- '-' ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Kuparuk Field June 6,2006 Corrosion Well Initial top Vol. of cement Final top of Cement top Royfill4048 inhibitor/ Name PTO# of cement pumped cement off date RG2041 vol vol. sealant date ft bbls ft qal gal 5/19/2006 21=>-406:": 20+022· 4 0.0 A na 5] 1-7.1 5/19/2006 2P-415a 201-226 5.5 0.0 5.5 na 7.1 30.9 5/19/2006 :2P-41Z 2Q>1~9 7.5 2.5 5/1/2006 '5.7 '9- 511812006 2P-419 204-017 1 0.0 1 na 6.7 0 5/18/2006 '2P420' 201-182 3.5 0.0: 3:5. na ~'. 7.1 17.3 . 5118/2006 2P-422a 202-067 13.5 2.3 2.5 5/1/2006 7.1 10.7 5/18/2006 2P-424a .204-009 . 4~5 0.0 4.5 -nà .5.7 17.6 511' 81200_6' 2P-427 202~018 10 1.6 2.5 5/1/2006 7.1 13.7 5/18/2006 2P429 201-102 2 0.0 . 2 na 3.8 5.7 5/1812006 2P-431 202-053 13 1.9 2.5 5/1/2006 7.1 10.1 5/18/2006 2p;;.432 ' '202;;091. 8~5 2.5 .5/1/2006 5.7 13.8 511812006 2P-434 203-153 14 2.0 2.5 5/1/2006 5.7 6.2 5/18/2006 -2P438 , 2à1';öä2 Õ 5 na 5.7 21.9- 5l18/2006- 2P-441 202-107 15 2.0 2.5 5/1/2006 7.1 13.1 5/18/2006 2Pi.443-~ ;'.' :204-032' 3.5 0.0 3.5 na 8~7 . 11.4 . 5/1'812006 2P-447 203-154 2.5 0.0 2.5 na 9.5 0 5/18/2006 2P-448a' '···202:.ðO:S: t~5 0.0 1.5 na 9.5 0 5/18/2006 2P-449 204-026 3 0.0 3 na 5.7 11.5 5/31/2006 2P-451 202-008 10 2.1 2.5 5/1/2006 '7.1 . 6.5 5/18/2006 ) ConocóPhillips Alaska E t"" .,~,",~ .., ,.. 'nr"'" ~: '\. '.~ ~r~ :¡'t '\./¡/ :r*D i. ,W ,,:>::;;7 ~"-,> ,;.;. ,~~" ~ U\\II 't..;"ì m~gl G uC;ì}¡ij~~, Am;J'l:iJnígle P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 ~rYf- - Ó11) June 06, 2006 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 SC/;\NNED JUN 2. ? 2006 Dear Mr. Maunder: Enclosed please find a spreadsheet with a list of wells from the Kuparuk field (KRU). Each of these wells was found to have a void in the conductor by surface casing annulus. The voids that were greater than 6 feet were first filled with cement to a level of2.5 feet. The remaining volume, 2.5 to 6 feet of annular void respectively was coated with a corrosion inhibiter, RG2401, then filled with a viscous hydrocarbon based sealant, Royfill 404B, engineered to prevent water from entering the annular space. As per previous agreement with the AOGCC, this letter and spreadsheet serves as notification that the treatments took place and meets the requirements of form 10-404, Report of Sundry Operations. The cement top-fill operation was completed on May 05,2006. SchlumbergerWell Services mixed 15.7 ppg Arcticset I in a blender tub. The cement was pumped into the conductor bottom and cemented up via a hose run to the existing top of cement. The corrosion inhibitor and sealant were pumped in a similar manner on May 18th, 19th and 31 S\ 2006. The attached spreadsheet presents the well name, top of cement depth prior to filling, and volumes used on each conductor. Please call Marie McConnell or myself at 907-659-7224, if you have any questions. ~2J ~errR<lein ConocoPhillips Problem Well Supervisor Attachment ) ) ConocoPhillips Alaska Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off ," . ';:~:~(2~~ô6' .' 2P-415 ~)(i2P~¡¡;7 " 2P-419 ~·:··:\~:ìÞ~n: ":,: . 2P-422 ;:~:,:Y~P~:'" .. 2P-427 ·.:!~2~:..::·· 2P-431 ...':.21i~~;'· 2P-434 '. ··;:·!P43&:·,::· :~.: '. .,' 2P-441 ":2Þ'~~;. . .~, :': 2P-447 ':··iP';443: 2P-449 .·.2P4t· I nitial top of cement ft .·4. ." 5.5 ·t~s:: ' .' 1 ··$~5:·'· 13.5 .' .'..4~5:· . ...., 10 ·>2~· . 13 ; > "'8~~·.·". 14 :.tJ.::·.. ",:'" :'.;" . 15 ."3.5.::: " 2.5 ::.'··1,~5·: ..' 3 :':1-0. . Vol. of cement pumped bbls . :0';0 . 0.0 '.òfl· , 0.0 '.:" :.' '~:on),::: . . 2.3 :". :::" ':'o~O' ~:" ....:.~... :'" 1.6 :. i,' " . '..0::0 .' 1.9 . ··.·O~9.··· 2.0 ':,)~:ò>' ". 2.0 Œ()" .. 0.0 ·:0:0: . 0.0 ..... Z1' Final top of cement ft .4. 5.5 ····2~5 . 1 ::":3.5' .... 2.5 ,·':4~5· 2.5 .; ·····:2:·, . 2.5 . '~Zi5::"\ 2.5 " ·.:.:~;5 .: . 2.5 '. :.: ·'::3~5·.:. 2.5 ·:::1.~5·· 3 2.5'· .' Cement top off date RG2041 voi J gal ..5~:7 7.1 ,',5:.:7: '. . 6.7 ·7~:t. 7.1 " ' . :' ..5·~7 :'.:" . 7.1 . ·.3·;8:. .., 7.1 ,." ·'5..7..' .. ,. 5.7 :····'5;7·: 7.1 .~ '>. :8.7> ..... 9.5 ····9.5: 5.7 .'.:' .'7:1· Kuparuk Field June 6,2006 F.'Ia na .,. .', :5¡'1120Ð~. . na '. ::~i'~' 5/1/2006 ". '" ,:ne(:'::, 5/1/2006 : :."'na,"''':'. . . ,',.\ ., ; '", 5/1/2006 :! :51.1/2oøtl· 5/1/2006 :'··'·:,;:·n3:··.· . . 5/1/2006 ·····nit:;:.' na . :'oa na '51.112006 . Royfill4048 vol. qal .1 ·1:7.t· 30.9 . ,·.:9·~'·· o .17.3..: ..... 10.7 '. . .1-7·; 6, 13.7 .' .'5:~.7 10.1 1:3.8:' 6.2 "'2L9' 13.1 : :1'.1-.4 o '" '0 11.5 '6.5 Corrosion inhibitor/ sealant date 5/19/2006 . . :5/1.91200"6: .;. 5/19/2006 . :', :~m_20è6;,:·: 5/18/2006 '. :.': .·~þf·tft_:·.:"'· 5/18/2006 ·::·.··:5/!i.812Ø06;·; .':' 5/18/2006 . "'" ' , . ,: > .....:·Sltl8120Oti';i-:; 5/18/2006 ...... ::,':,Sli~:<;': 5/18/2006 . . _ ..:l:il~Q~oœ;:· ;::: . '¡¡¡"J~~~,~I ; .. .' . 5/18/2006 .' :.5f;1812Ð~::: 5/18/2006 . '. '. 511S12QQ6"·-:,' 5/31/2006 . 5i1;812006..·.·. G f.J.,,,A ~o ~ ~ DATA SUBMITTAL COMPLIANCE REPORT 3/2/2006 Permit to Drill 2040170 Well Name/No. KUPARUK RIV U MELT 2P-419 Operator CONOCOPHILLlPS ALASKA INC API ~ 1o~4~!o~-'ðO A. t) ~ t.f MD 1 0945 ~ TVD 5671/' Completion Date 3/6/2004 r- Current Status WAGIN REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes --------~,._~ - -------~.._--_._._----------------~_..._-~ -_.__._._._~ ------------,-,._-- -_._._.~-- DATA INFORMATION Types Electric or Other Logs Run: GRlRes/Den/New, USIT (data taken from Logs Portion of Master Well Data Maint Well Log Information: . Log/ Electr Data Digital Dataset Log Log Run Interval OH/ Type . Med/Frmt Number Name Scale Media No Start Stop CH Received Comments r:;// Directional Survey 6/17/2004 Cement Evaluation 25 Col 3390 10065 Case 2/18/2004 Ultrasonic Imager Tool - .-' I /", US IT Cement Bond Log I ~.' . 'Rpt Directional Survey 108 1 0945 3/3/2004 ~. ~ Perforation 5 Blu 9965 10750 Case 3/26/2004 Perforating Record and SBHP og Pressure 5 Blu 9965 10750 Case 3/26/2004 Perforating Record and SBHP I - !Log Cement Evaluation 5 Blu 9792 10803 Case 3/26/2004 Cement Bond Log - SCMT- I CNPresslTemp Pressure 5 Blu 9792 10803 Case 3/26/2004 Cement Bond Log - SCMT- CNPresslTemp Temperature 5 Blu 9792 10803 Case 3/26/2004 Cement Bond Log - SCMT- CNPresslTemp . C Lis 12654 Gamma Ray 108 1 0945 Open 4/21/2004 RWD- GRlMPRlCCN/ORD/GRAP HIC IMAGE FILES 12654 LIS Verification /' 108 1 0945 Open 4/21/2004 RWD-GRlMPRlCCN/ORDI 12654 Neutron 25 Blu ,.tIJ) 108 1 0945 Open 4/21/2004 CCN, ORD, RWD MPR, tV'O PRESS, DIR 12654 Neutron 25 Blu 108 10945 Open 4/21/2004 CCN, ORD, RWD MPR, PRESS, DIR 12654 Induction/Resistivity 25 Blu N(f) 108 1 0945 Open 4/21/2004 MPR/GRlRWD 12654 Induction/Resistivity 25 Blu Ì'1ID 108 1 0945 Open 4/21/2004 MPRlGRlRWD Injection Profile 5 Blu 10000 10295 Case 9/28/2005 Injection Profile L SPINITEMP/PRESS/GRAD 10 17 Sep 2005 Permit to Drill 2040170 MD 10945 TVD 5671 Well Cores/Samples Information: Name ADDITIONAL INFORMATION Well Cored? Y/N Chips Received? Y/N Analysis Y / N Received? DATA SUBMITTAL COMPLIANCE REPORT 3/2/2006 Well Name/No. KUPARUK RIV U MELT 2P-419 Operator CONOCOPHILLlPS ALASKA INC Completion Date 3/6/2004 Completion Status WAGIN Interval Start Stop Sent Received Daily History Received? Formation Tops Comments: Current Status WAGIN Sample Set Number Comments @ API No. 50-103-20483-00-00 UIC Y Compliance Reviewed By: Date: . . -- Con ocóP't, ill ips e Randy Thomas Kuparuk Drilling Team Leader Drilling & Wells P. O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-6830 March 29, 2004 Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Avenue Suite 100 Anchorage, Alaska 99501 Subject: Well Completion Report for 2P-419 (APD # 204-017) Dear Commissioner: ConocoPhillips Alaska, Inc. submits the attached Well Completion Report for the recent drilling operations of the Meltwater well 2P-419. If you have any questions regarding this matter, please contact me at 265-6830 or Philip Hayden at 265-6481. ~!~ r¡£~MWj Kuparuk Drilling Team Leader CPAI Drilling RECEIVED MAtt 3 0 2004 Alaskl Oil & Gas Cons, Commìaeion Andunge RT Iskad e STATE OF ALASKA e ALASKA Oil AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil D Gas U Plugged U Abandoned U Suspended D WAG 0 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development D Exploratory D GINJ D WINJ D WDSPL D No. of Completions _ Other - Service 0 Stratigraphic Test D 2. Operator Name: 5. Date comp"ji)fik"'- (P I 2L~( 12. Permit to Drill Number: ConocoPhillips Alaska, Inc. or Aband.: j;eR,,, (y"~ ,J..l 204-017 I 3. Address: 6. Date Spudded: '1- & c- ""f 13. API Number: P. O. Box 100360, Anchorage, AK 99510-0360 January 21, 2004 , 50-103-20483-00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: ./ Surface: 888' FNL, 2148' FWL, Sec. 17, T8N, R7E, UM February 5, 2004 2P-419 At Top Productive 8. KB Elevation (It): 15. Field/Pool(s): Horizon: 2587' FSL, 127' FWL, Sec. 20, T8N, R7E, UM 28' RKB Kuparuk River Field Total Depth: 9. Plug Back Depth (MD + TVD): Meltwater Oil Pool 1962' FSL, 287' FEL, Sec. 19, T8N, R7E, UM 10814' MD I 5608' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD): 0/ 16. Property Designation: Surface: x- 444108 ,/ y- 5868988 ./ Zone- 4 ./ 10945' MD I 5671' TVD ADL 373112/389058 TPI: x-442058 y- 5861918 Zone-4 11. Depth where SSSV set: 17. Land Use Permit: Total Depth: x-441641 ./ y- 5861297 0/ Zone-4 Landing nipple @ 505' L32092 I 32409 18. Directional Survey: Yes 0 NoU 19. Water Depth, if Offshore: 20. Thickness of NIA feet MSL Permafrost: 1399' MD 21. Logs Run: GR/Res/Den/Neu, US IT 22. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 16" 62.5# B Surface 108' 42" 110 sx LiteCrete , 9.625" 40# L-80 Surface 3287' 12.25" 396 sx AS Lite, 297 sx LiteCrete 7" 26# L-80 Surface 10065' 8.5" 223 sx Class G, 209 sx Class G 3.5" 9.3# L-80 9893' 10943' 6.125" 51.7 bbls Class G 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state 'none"): SIZE DEPTH SET (MD) PACKER SET (MD) 4.5" I 3.5" 9946' 9893' / 10216'-10236' MD 5339'-5348' TVD 6 spf " 10250'-10290' MD 5354'-5371' TVD 6spf 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. " 10510'-10570' MD 5467'-5493' TVD 6spf DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED / 10644' -10664' MD 5527'- 5537' TVD 6 spf NIA 26. PRODUCTION TEST Date First Injection Method of Operation (Flowing, gas lilt, etc.) March 10, 2004 WAG injection Date of Test Hours Tested Production for OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO NIA Test Period --> Flow Tubing Casing Pressure Calculated OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY - API (corr) press. psi 24-Hour Rate -> 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). RECEIV'ED Submit core chips; if none, state "none". CrH" ~:.~fiQi MÀK 3 0 2004 NONE ._. ~J::4i>" lii G8S rrmc ¡ . . ~9F'l APR~ lqQ\ .J. ",' "-'.OM. ,. Form 10-407 Revised 2/2003 CONTINUED ON REVERSE SIDE Submit in duplicate /~ , /' ,: !..... 28. 29. GEOLOGIC MARKERS FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". 2P-419 T3 T2 10107' 10756' 5294' 5580' NIA 30. LIST OF ATTACHMENTS Summary of Daily Operations, Directional Survey, Schematic 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Philip Hayden @ 265-6481 Title: Phone KUDaruk Team Leader Date 2. ì ~/J.;2.:>D'i / Prepared by Sharon Allsup-Drake INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1a: Classification of Service wells: Gas injection, water injection, Water-Alternating-Gas Injection, salt water disposal, water supply for injection, observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: the Kelly Bushing elevation in feet abour mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 2/2003 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 1/20/2004 18:00 - 20:00 20:00 - 22:00 22:00 - 00:00 00:00 - 03:00 1/21/2004 03:00 - 06:00 06:00 - 08:45 08:45 - 09:15 09:15-11:15 11: 15 - 11 :30 11 :30 - 13:00 13:00 - 14:30 14:30 - 15:00 15:00 - 16:00 16:00 - 00:00 1/22/2004 00:00 - 12:00 12:00 - 00:00 1/23/2004 00:00 - 04:30 04:30 - 06:00 06:00 - 07:30 07:30 - 08:15 08:15 - 09:30 09:30 - 10:30 10:30 -11:00 11 :00 - 15:00 15:00 - 16:00 16:00 - 21:30 21 :30 - 22:30 22:30 - 23:00 23:00 - 00:00 1/24/2004 00:00 - 01 :00 2.00 MOVE 2.00 MOVE 2.00 MOVE 3.00 MOVE RURD MOVE MOVE MOVE MOVE MOVE MOVE MOVE 3.00 MOVE RURD MOVE 2.75 WELCT SURFAC 0.50 RIGMNT RSRV SURFAC 2.00 DRILL PULD SURFAC 0.25 WELCT BOPE SURFAC 1.50 DRILL CIRC SURFAC 1.50 DRILL DRLG SURFAC 0.50 DRILL SFTY SURFAC 1.00 RIGMNT RGRP SURFAC 8.00 DRILL DRLG SURFAC 12.00 DRILL DRLG SURFAC 12.00 DRILL DRLG SURFAC 4.50 DRILL DRLG SURFAC 1.50 DRILL CIRC 1.50 DRILL 0.75 DRILL 1.25 DRILL 1.00 DRILL 0.50 CASE 4.00 DRILL 1.00 CASE 5.50 CASE TRIP CIRC TRIP TRIP RURD PULD RURD RUNC SURFAC SURFAC SURFAC SURFAC SURFAC SURFAC SURFAC SURFAC SURFAC 1.00 CASE CIRC SURFAC 0.50 CEMEN PULD SURFAC 1.00 CEMEN CIRC SURFAC 1.00 CEMEN CIRC SURFAC Prepare rig for move to 2P-419. Move rig off 2P-447. Spot Sub over 2P-419. Spot Pits, Pumps, Motors, Boilers, Rockwasher & Pipe shed complexes. Hook up Air, Water, Steam, Glycol & Mud lines, Prep rig for acceptance. Accept rig @ 06:00 hrs 1/21/2004, Nipple up Diverter, Mix spud mud, Rig up tank farm, Pick up BHA tools to rig floor. Service top drive and blocks. Make up 12-1/4" BHA #1 Function test Diverter- OK, Test waived by AOGCC Chuck Schieve. Fill conductor, Check for leaks, Prep for spud. Spud well @ 13:00 hrs 1/21/2004, Drill fl 108' to 196'. Pre- Spud safety meeting in Doghouse. Attempt to repair rig Gai-Tronics gas alarm. Drill f/196' to 792' ART = 2.3 hrs AST = 3.0 hrs, Run Gyro surveys as needed, Pump Hi-vis weighted sweeps every 3 to 5 stands, WOB 10/20K, 80 RPM, 576 GPM @ 1100 psi, UP 77K, DN 75K, ROT 75K, T02K. Drill f/792' to 1,940' ART = 2.8 hrs AST = 5.0 hrs, Pump Hi-vis weighted sweeps every 3 to 5 stands, WOB 5/30K, 80 RPM, 634 GPM @ 2000 psi, UP 85K, DN 90K, ROT 90K, TO 2/4K on/2K off, Mud weight 9.2 ppg wI 220 vis, BGG 70 units, Had 897 units @ 1,860' & 926 units @ 1,928'. Drill f/1 ,940' to 2,961' ART = 6.3 hrs AST = 2.2 hrs, Pump Hi-vis weighted sweeps every 3 to 5 stands, WOB 20/30K, 90 RPM, 635 GPM @ 2400 psi, UP 95K, DN 85K, ROT 90K, TO 8K onl 6K off, Raised mud weight to 10.5 ppg @ 2,350' wI vis 180, BGG 75 units, BGG increased to 120 units @ 2,950' Drill f/2,961' to 3,292' ART = 3.3 hrs AST = .4 hrs, Pump Hi-vis weighted sweep at 3000' (Showed hole clean), WOB 10/35K, 90 RPM, 635 GPM @ 2400 psi, UP 97K, DN 90K, ROT 92K, TO 5/1 OK onl 4K off, Mud weight 10.5 ppg wI vis 180, BGG 150 to 200 units. Pump Hi-vis weighted sweep & Circ hole clean with 3 btm's up at rate of 650 gpm @ 2300 psi & 90 RPM, Observe well-OK. Back ream out of hole to 2,223' at drilling rate. Circ hole clean with 650 GPM @ 2150 psi & 110 RPM. Observe well, POOH on elevators to BHA @ 1,108' Lay down Ghost reamer, POOH & stand back HWDP. Pick up casing equip. to rig floor. Lay down NMDC's, Down load MWD, Lay down BHA. Rig to run 9-5/8" casing. PJSM, Run 9.625" 40# BTC csg to 3,287' MD ( Ran total 84 jts) - M/U hanger - MU landing jt, UP 125K, DN 95K. Break circ wI Franks fill up tool, Stage circ rate up to 6 bpm @ 500 psi, Btm's up gas 210 units, BGG 44 units. Rig down Franks fill up tool, Rig up Dowell cement head. Circ & condition mud for cement, Lower propertys from PV 42, YP 57 to PV 31, YP 14, Circ at rate of 6 bpm @ 375 psi, Casing wt. UP 125K, DN 105K. Circ & condition mud for cement, Lower propertys from PV 42, YP 57 to PV 31, YP 14, Circ at rate of 6 bpm @ 375 psi, Casing wt. UP 125K, Printed: 3/16/2004 2:57:19 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 1124/2004 00:00 - 01 :00 1.00 CEMEN CIRC SURFAC DN 105K. 01 :00 - 03:30 2.50 CEMEN PUMP SURFAC Rig Dowell, Mix & pump 5 bbls CW100 at 8.3 ppg at rate of 5.0 bpm @ 130 psi, Shut down, Test lines to 3500 psi, Continue pumping CW100 to total of 40 bbls, Mix & pump 40 bbls MudPUSH II with red dye added mixed at 10.2 ppg at rate of 4.1 bpm @ 200 psi, Shut down and drop btm plug, Mix & pump 396 sxs (314.5 bbls) Lead ArcticSet III cmt mixed at 10.7 ppg wI additives at rate of 7.0 bpm @ 210 psi, Followed by 297 sxs (130.7 bbls) Tail LiteCRETE cmt mixed at 12.0 ppg wI additives at rate of 6.9 bpm @ 275 psi, Shut down and drop top plug, Displace cmt wI 20 bbls fresh water, Shut down and turn over to rig pumps and continue to displace w/219.5 bbls 10.4 ppg mud (total of 239.5 bbls to bump plug) at rate of 7.0 bpm @ 650 psi, Slowed rate to 3.0 bpm @ 375 psi for last 10 bbls of displacement, Bump plug w/1 000 psi, Floats held- OK, CIP @ 03:15 hrs 1/24/04, Had good returns thru out job, Reciprocate csg. 15' until CW1 00 to surface then pipe got tight, Had 136.6 bbls good cmt returns to surface. 03:30 - 04:00 0.50 CEMEN SURFAC Rig down cmt head & landing joint. 04:00 - 07:30 3.50 WELCT SURFAC Nipple down diverter system. 07:30 - 08:15 0.75 WELCT SURFAC Nipple up FMC Gen 5 wellhead and test same to 1000 psi fl 10 min.- OK 08: 15 - 11 :00 2.75 WELCT SURFAC Nipple up BOPE 11 :00 - 16:45 5.75 WELCT SURFAC Rig & Test all BOPE to 250 psi low & 5000 psi high, Hydril to 250 psi low & 3500 psi high, Test witnessed & approved by AOGCC Chuck Scheeve, Blow down choke manifold, Rig down test equip., Install wear bushing. 16:45 - 20:15 3.50 DRILL PULD SURFAC Pick up 87 joints 5" drill pipe and stand back in derrick. 20: 15 - 20:45 0.50 DRILL PULD SURFAC Pick up BHA tools from beaver slide to rig floor to warm up. 20:45 - 23:30 2.75 DRILL PULD SURFAC Pick up 87 joints 5" drill pipe. 23:30 - 00:00 0.50 DRILL CIRC SURFAC Circ drill pipe clean at a rate of 22 BPM @ 900 psi wI 75 RPM in case of any cement chips in pipe. 1/25/2004 00:00-01:15 1.25 DRILL TRIP SURFAC Blow down top drive, POOH & stand back 29 stds 5" D.P. 01 :15 - 01 :45 0.50 RIGMNT RSRV SURFAC Service top drive. 01 :45 - 04:45 3.00 DRILL PULD SURFAC Make up BHA, Pick up bit, motor, NMstab, XO, MWD/LWD, Program MWD, Orient motor, RIH. 04:45 - 08:30 3.75 RIGMNT RGRP SURFAC Repair Service loop on top drive. 08:30 - 09:30 1.00 DRILL PULD SURFAC RIH wI NMDC's, Surface test MWD tools, RIH wI HWDP, Pick up Ghost reamer. 09:30 - 12:00 2.50 DRILL TRIP SURFAC Pick up 5" Drill pipe from pipe shed to 3,203'. 12:00 - 13:30 1.50 DRILL CIRC SURFAC Circ btm's up, Condition airiated mud. 13:30 - 15:30 2.00 CASE DEOT SURFAC Rig & test 9-5/8" casing to 3500 psi f/30 min.- OK. 15:30 - 16:45 1.25 DRILL DRLG SURFAC Drill out Float collar @ 3,203', Cement, Float shoe @ 3,287'. 16:45 - 17:00 0.25 DRILL DRLG SURFAC Drill 20' new hole to 3,312' ART = 0.2 hrs. 17:00 - 17:30 0.50 DRILL CIRC SURFAC Change over to 10.3 ppg clean LSND mud. 17:30 - 18:30 1.00 DRILL FIT SURFAC Perform FIT of 18.0 ppg wI 10.3 ppg mud, 2,351' TVD, 940 psi. 18:30 - 23:00 4.50 DRILL DRLG INTRM1 Drill f/3,312' to 3,675' ART= 2.0 hrs AST= 1.0 hrs WOB 15/25K, RPM 90, 550 gpm @ 2600 psi, UP 125K, DN 77K, ROT 97K, TO 6/11 K on I 5K off, Ave. ECD's 11.8 to 12.2 ppg, Pumping Hi-vis weighted sweeps every 3 to 4 stands, Mud wt. 10.3 ppg, Maintaining 5 ppb fine LCM in mud, Ave. BGG 35 units. 23:00 - 23:30 0.50 DRILL CIRC INTRM1 Circ & obtain PWD base line of 11.4 ppg clean hole. 23:30 - 00:00 0.50 DRILL DRLG INTRM1 Drill fl 3,675' to 3,710' ART = 0 hrs AST = 0.4 hrs WOB 15/25K, 550 gpm @ 2600 psi, UP 125K, DN 77K, ROT 94K, 10.3 ppg, Maintaining 5 ppb fine LCM in mud, Ave. BGG 35 units. Printed: 3/16/2004 2:57: 19 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 1/26/2004 00:00 - 19:30 19.50 DRILL DRLG INTRM1 Drill fl 3,710' to 4,974' ART= 10.5 hrs AST= 1.3 hrs WOB 10/25K, RPM 90, 550 gpm @ 3000 psi, UP 143K, DN 86K, ROT 105K, TO 5/1 OK on I 5/11 K off, Ave. ECD's 11.8 to 12.2 ppg, Pumping Hi-vis weighted sweeps every 3 to 4 stands, Mud wt. 10.3 ppg, Maintaining 5 ppb fine LCM in mud, Ave. BGG 45 units. 19:30 - 20:00 0.50 DRILL CIRC INTRM1 Pump Hi-vis sweep around, Hole very clean. 20:00 - 22:00 2.00 DRILL TRIP INTRM1 Back ream out of hole f/4,974' to 3,636' at drilling rate- Hole in very good shape, Pulled last 3 stands slow & circ hole clean- Had heavy amont of cuttings for short time on btm's up. 22:00 - 00:00 2.00 DRILL TRIP INTRM1 Monitor well- OK, Pump dry job, POOH on elevators fl 3,636' to Ghost reamer @ 1,111', Lay down Ghost reamer & clean rig floor. 1/27/2004 00:00 - 01 :00 1.00 DRILL TRIP INTRM1 RIH to 3,206', Fill pipe, Blow down top drive. 01 :00 - 01 :30 0.50 RIGMNT RSRV INTRM1 Service top drive & blocks. 01 :30 - 02:15 0.75 DRILL TRIP INTRM1 RIH to 4,878', Precautionary wash f/4,878' to 4,974'- Hole in very good shape. 02:15 - 14:45 12.50 DRILL DRLG INTRM1 Drill f/4,974' to 6,175' ART= 8.1 hrs AST= 0.9 hrs WOB 10/25K, RPM 90,550 gpm @ 3150 psi, UP 140K, DN 80K, ROT 98K, TQ 8/11K on I 8K off, Ave. ECD's 11.8 to 12.5 ppg, Pumping Hi-vis weighted sweeps every 3 to 4 stands, Mud wt. 10.4 ppg, Maintaining 5 ppb fine LCM in mud, Ave. BGG 45 units, Note; Had 8,440 units connection gas from connection @ 6,082' MD 3,592' TVD. 14:45 - 16:00 1.25 DRILL CIRC INTRM1 Circ at reduced circ rate to achieve 11.6 ppg ECD, Circ btm's up - No gas or mud weight cut. 16:00 - 16:45 0.75 DRILL OBSV INTRM1 Shut down & monitor well for 2.5 min.- Well flowing, Circ btm's up, Had 385 units gas, Mud cut to 10.1 ppg. 16:45 - 19:00 2.25 DRILL CIRC INTRM1 Raise mud weight from 10.4 to 10.7 ppg, Shut down pumps 2 min.- well flowing, Circ btm's up at rate of 550 GPM @ 3000 psi, Had 1130 units gas, Mud cut to 9.8 ppg, BGG 85 units, ECD's 12.0 ppg. 19:00 - 19:45 0.75 DRILL OBSV INTRM1 Shut down & monitor well for 5 min.- Well flowing- Had 0.5 bbl gain in 5 min., Circ btm's up, Had 5430 units gas, Mud cut to 8.8 ppg. 19:45 - 22:30 2.75 DRILL CIRC INTRM1 Raise mud weight from 10.7 to 10.9 ppg at rate of 550 GPM @ 3000 psi, Shut down pumps 6 min.- well flowing- Had 0.5 bbl gain in 6 min., Circ btm's up, Had 4010 units gas, Mud cut to 9.3 ppg, Make connection in 3.5 min, Circ btm's up- Had 780 units connection gas- Mud cut to 10.5 ppg, Record SPR's, BGG 85 to 95 units, ECD's 12.3 ppg. 22:30 - 23:30 1.00 DRILL DRLG INTRM1 Drill fl 6,175' to 6,266' ART = 0.75 hrs AST = 0 hrs Control drill @ 100 to 125 ftIhr to control ECD's, WOB 5/10K, RPM 90, 550 gpm @ 3100 psi, UP 145K, DN 137K, ROT 106K, TO 8/11K on 18K off, Ave. ECD's 12.4 to 12.5 ppg, Mud wt. 10.9 ppg, Maintaining 5 ppb fine LCM in mud, Ave. BGG 85 to 100 units, Had 404 units gas from recording SPR's. 23:30 - 00:00 0.50 DRILL CIRC INTRM1 Shut down & monitor well for 5 min.- Well flowing- Had 0.5 bbl gain in 5 min., Circ btm's up, Had 4030 units gas, Made connection in 3.5 min, Had 1460 units connection gas. Note: No mud lost in hole. 1/28/2004 00:00 - 00:15 0.25 DRILL CIRC INTRM1 Continue to Circ btm's up, Made connection in 3.5 min, Had 1460 units connection gas. 00:15 - 12:00 11.75 DRILL DRLG INTRM1 Drill fl 6,266' to 7,196' ART = 7.8 hrs AST = 0.7 hrs Control drill @ 100 to 125 ftIhr to control ECD's, WOB 10/25K, RPM 90, 475 gpm @ 2950 psi, UP 160K, DN 80K, ROT 112K, TO 9/13K on I 11 K off, Ave. ECD's 12.4 to 12.6 ppg, Mud wt. 10.9 to 11.0 ppg, Pump Hi-vis unweighted sweeps every 4 stands, Maintaining 5 ppb fine LCM in mud, Ave. BGG 85 to 105 units, Connection gas 435 to 1850 units, No mud lost. Printed: 3/16/2004 2:57:19 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 1/28/2004 12:00 - 00:00 12.00 DRILL DRLG INTRM1 Drill fl 7,796' to 8,085' ART = 8.7 hrs AST = 1.0 hrs Control drill @ 100 to 125 ftIhr to control ECD's, WOB 10/25K, RPM 90, 475 gpm @ 3050 psi, UP 170K, DN 92K, ROT 115K, TO 13/16K on I 15/17K off, Ave. ECD's 12.4 to 12.7 ppg, Mud wt. 10.9 to 11.0 ppg, Pump Hi-vis unweighted sweeps every 4 stands, Maintaining 5 ppb fine LCM in mud, Ave. BGG 45 to 90 units, Connection gas 408 to 1670 units, No mud lost. 1/29/2004 00:00 - 12:00 12.00 DRILL DRLG INTRM1 Drill fl 8,085' to 8,868' ART= 7.4 hrs AST= 1.5 hrs Control drill @ 100 to 125 ftIhrto control ECD's, WOB 15/25K, RPM 90, 475 gpm @ 3050 psi, UP 185K, DN 93K, ROT 122K, TO 14/17K on /14K off, Ave. ECD's 12.4 to 12.7 ppg, Mud wt. 10.9 to 11.0 ppg, Pump Hi-vis unweighted sweeps every 4 stands,Maintaining 5 ppb fine LCM in mud, Ave. BGG 45 to 85 units, Connection gas 350 to 1150 units, No mud lost. 12:00 - 21 :00 9.00 DRILL DRLG INTRM1 Drill fl 8,868' to 9,517' ART = 6.4 hrs AST = 0.9 hrs Control drill @ 100 to 125 ftIhr to control ECD's, WOB 15/25K, RPM 90, 475 gpm @ 3150 psi, UP 196K, DN 92K, ROT 120K, TO 14/19K on I 18/19K off, Ave. ECD's 12.4 to 12.8 ppg, Mud wt. 10.9 to 11.0 ppg, Pump Hi-vis unweighted sweeps every 4 stands, Maintaining 5 ppb fine LCM in mud, Ave. BGG 45 to 85 units, Connection gas 340 to 1150 units, No mud lost. 21 :00 - 22:00 1.00 DRILL CIRC INTRM1 Pump Hi-vis weighted sweep, Circ hole clean, Change shaker screens to 38 mesh, Add 10 ppb Calcium carbonate, Mix II, G-seal 22:00 - 00:00 2.00 DRILL CIRC INTRM1 Monitor well 7min.(Mild flow- Well swabs when pipe is picked up), Raise mud weight from 10.9+ to 11.2 ppg, Slow pump rate down to 375 GPM @ 2150 psi, Had 2160 units gas from 7 min. flow check, Mud cut to 10.2 ppg, BGG 50 units, ECD's 12.6 ppg. No mud loss. 1/30/2004 00:00 - 00:45 0.75 DRILL CIRC INTRM1 Flow check well 10 min.- Mild flow, Circ btm's up at 375 GPM @ 2200 psi- Had 700 units gas on btm's up. 00:45 - 03:15 2.50 DRILL CIRC INTRM1 Raise mud wt. fl 11.2 to 11.4 ppg, Flow check well 15 min.- Well static, Circ btm's up- Had 300 units gas on btm's up, No Mud lost, ECD's 12.7 to 12.9 ppg. Note; All gas peaks come from 6,082' MD- 3,592' TVD (Depth of original gas influx). 03:15 - 04:30 1.25 DRILL WIPR INTRM1 Back ream out to 9,057' (10 stands) at 380 GPM @ 2200 psi & 90 RPM, Hole in good shape. 04:30 - 05:00 0.50 DRILL CIRC INTRM1 Circ btm's up to check gas- Had 145 units. 05:00 - 11 :45 6.75 DRILL WIPR INTRM1 Back ream out of hole to 4,971' at rate of 380 GPM @ 2200 psi & 90 RPM- Hole in good. 11 :45 - 13:30 1.75 DRILL CIRC INTRM1 Circ hole clean, Increase pump rate to 538 GPm @ 2800 psi, ECD's 12.6 ppg, No mud lost, Monitor well- Slight flow, Circ btm's up - Had 62 units. 13:30 - 14:00 0.50 DRILL WIPR INTRM1 RIH fl 4,971' to 6,080'- Hole in good. 14:00 - 14:45 0.75 DRILL CIRC INTRM1 Circ btm's up at rate of 493 GPM a@ 2650 psi, ECD's 12.6, Gas on btm's up 1450 units. 14:45 - 15:30 0.75 DRILL WIPR INTRM1 RIH to 7,470'- Hole in good shape. 15:30 - 16:15 0.75 DRILL CIRC INTRM1 Circ btm's up at rate of 508 GPM a@ 2900 psi, ECD's 12.69, Gas on btm's up 1920 units. 16:15 - 17:00 0.75 DRILL WIPR INTRM1 RIH to 9,428', Precautionary ream to 9,517'. 17:00 - 18:30 1.50 DRILL CIRC INTRM1 Circ btm's up at rate of 380 GPM @ 2150 psi, ECD's 12.62, Gas on btm's up 1980 units, Stage pump rate up to 480 GPM, ECD's 12.5. 18:30 - 00:00 5.50 DRILL DRLG INTRM1 Drill fl 9,517' to 9,862' ART = 3.7 hrs AST = 0.6 hrs Control drill @ 100 to 125 ftIhr to control ECD's, WOB 15/25K, RPM 90, 475 gpm @ 3500 psi, UP 190K, DN 98K, ROT 130K, TO 15/21K on /19/21K off, Ave. Printed: 3/16/2004 2:57:19 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 1/30/2004 18:30 - 00:00 5.50 DRILL DRLG INTRM1 ECD's 12.6 to 12.9 ppg, Mud wt. 11.4 ppg, Pump Hi-vis weighted sweeps every 3 stands, Maintaining 5 ppb fine LCM in mud, Ave. BGG 65 to 92 units, Connection gas 174 to 400 units, No mud lost. 1/31/2004 00:00 - 03:45 3.75 DRILL DRLG INTRM1 Drill fl 9,862' to 10,074' (5,280' TVD) - (7" casing point), ART = 2.2 hrs AST = 0.6 hrs Control drill @ 100 to 125 ftIhr to control ECD's, WOB 15/25K, RPM 90, 475 gpm @ 3500 psi, UP 210K, DN 105K, ROT 137K, TO 15/21K on I 20K off, Ave. ECD's 12.6 to 12.9 ppg, Mud wt. 11.4 ppg, Pump Hi-vis weighted sweeps every 3 stands, Maintaining 5 ppb fine LCM in mud, Ave. BGG 45 to 75 units, Connection gas 135 to 265 units, No mud lost. 03:45 - 07:00 3.25 DRILL CIRC INTRM1 Circ btm's up for mud loggers (Comfirmed casing point) , Pump Hi-vis weighted sweep, Raise mud weight to 11.5 ppg at rate of 375 GPM @ 2150 and 90 RPM. 07:00 - 07:45 0.75 DRILL WIPR INTRM1 Back ream out to 9,521' at rate of 375 GPM @ 2150 psi & 90 RPM, Hole in good shape. 07:45 - 08:00 0.25 DRILL WIPR INTRM1 POOH on elevators to 9,149'- Hole in good shape, Gained 1.0 bbl on fill. 08:00 - 08:30 0.50 DRILL WIPR INTRM1 RIH to 10,074'- No problems. 08:30 - 10:00 1.50 DRILL CIRC INTRM1 Circ btm's up at rate of 375 GPM @ 2150 psi- Had 1320 units trip gas From 6,000', Had 145 units gas from btm., BGG 60 units 10:00 - 12:15 2.25 DRILL CIRC INTRM1 Pump Hi-vis sweep around, Mix & Spot 43 bbls. 30 ppb LCM Pili on btm. 12:15 - 12:45 0.50 DRILL TRIP INTRM1 POOH f/10,074' to 9,423', Gained 2.5 bbls on fill. 12:45 - 13:30 0.75 DRILL CIRC INTRM1 Circ btm's up at rate of 380 GPM @ 2150 psi- Had 3330 units trip gas From 6,000'. 13:30 - 15:45 2.25 DRILL CIRC INTRM1 Raise mud weight fl 11.5 to 11.6 ppg, Monitor well for 20 min.- Slight flow. 15:45 - 16:30 0.75 DRILL CIRC INTRM1 Circ btm's up at rate of 380 GPM @ 2150 psi- Had 500 units gas. 16:30 - 18:45 2.25 DRILL CIRC INTRM1 POOH 1 stand to 9,333', Raise mud wt. fl 11.6 to 11.7 ppg, Monitor well for 30 min.- well static. 18:45 - 20:00 1.25 DRILL CIRC INTRM1 Circ btm's up at rate of 380 GPM @ 2150 psi- Had 527 units gas. 20:00 - 00:00 4.00 DRILL TRIP INTRM1 Back ream out of hole f/9,333' to 6,085' at rate of 375 GPM @ 2150 psi and 90 RPM. Note; Received verbal extension on BOPE test from AOGCC until after 7" casing set. 2/1/2004 00:00 - 00:30 0.50 DRILL CIRC INTRM1 Circ btm's up @ 6,085' at rate of 375 GPM @ 1750 psi- Had 145 units gas. 00:30 - 02:45 2.25 DRILL CIRC INTRM1 Raise mud weight f/11. 7 to 11.9 ppg at rate of 375 GPM @ 1775 psi, No mud lost, Monitor well 15 min.- Well static. 02:45 - 03:45 1.00 DRILL TRIP INTRM1 POOH fl 6,085' to 4,971' on elevators (15 to 20K max drag), Hole taking proper fill, Pump dry job. 03:45 - 06:45 3.00 DRILL TRIP INTRM1 POOH to BHA @ 109', Monitored well at Shoe & BHA- Static. 06:45 - 08:15 1.50 DRILL PULD INTRM1 Lay down BHA, Remove A.A. sources, Lay down LWD, MWD, Stab's & motor. 08:15 - 10:30 2.25 WELCT EORP INTRM1 Pull wear bushing, Install test plug, Change top rams to 7", Test door seals to 3000 psi, Lay down test plug. 10:30 - 12:00 1.50 CASE RURD INTRM1 Rig up Doyon casing equip. 12:00 - 17:45 5.75 CASE RUNC INTRM1 PJSM, Run 7",26#, L-80, BTCM casing to 3,245'. 17:45 - 19:00 1.25 CASE CIRC INTRM1 Circ casing & annulas volume, Stage rate f/1 bpm @ 325 psi, to 5 bpm @ 500 psi, Btm's up gas 25 units, UP 99K, DN 63K. 19:00 - 21:30 2.50 CASE RUNC INTRM1 Continue running casing to 5,700', Last 15 joints - had decrease in displacment. 21 :30 - 00:00 2.50 CASE CIRC INTRM1 Circ btm's up wI 50 % returns, Stage rate f/1 bpm @ 500 psi to 2 bpm Printed: 3/16/2004 2:57:19 PM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: @ 650 psi, Increase LCM f/5 ppb to 10 ppb, UP 134K, DN 70K, Mud wt. 11.9 ppg, Losses subsiding close to btm's up, Lost 113 bbls mud while eire, Lost total of 166 bbls in hole as of Midnight. Continue to Circ btm's up wI Full returns at rate of 2 bpm @ 650 psi, Increase LCM f/5 ppb to 10 ppb, UP 134K, DN 70K, Mud wt. 11.9 ppg. Run & stage in hole f/5,700' to 8,500', Circ every 5 jts. at rate of 2 bpm @ 425 psi to 3 bpm @ 550 psi, Run csg at rate of 20 fpm, Circ btm's up @ 6380',7240',8500', Gas f/65 to 130 units, Lost 70 bbls mud while running & circ casing. Run & wash 7" casing to maintain circulation and to minimize losses fl 8,500' to 10,065', Run csg at rate of 20 fpm, 2 bpm @ 550 psi. Lay down Franks fill up tool, Blow down top drive, Rig up Dowell cement head, Circ btm's up at rate of 2.5 bpm @ 500 psi, 75% returns. Lost eletric power from CPF-2, Start rig engins & put on line. Note; Well flowed back 16 bbls while down for 30 min. Continue to circ btm's up, After full btm's up- Had full returns, Increase pump rate to 3.5 bpm @ 500 psi wI full returns, Max gas 725 units, Held PJSM for cement job, Wt. UP 245K, DN 92K. Note:Casing pulling tight 275K prior to shutting down for cmt.- Land casing on hanger, Shoe @ 10,065', Float collar @ 9,978', Baffle @ 9,936', Stage tool @ 6,198'. Note; Total mud lost for last 24 hrs. = 97 bbls, Total mud lost in well to date = 263 bbls. 1.25 CEMEN PUMP INTRM1 Cemented 1st stage of 7" csg, Dowell pumped 10 bbls of CW 100 at 8.3 ppg, pressure tested lines to 4,000 psi, pumped add. 20 bbls of CW 100, followed by 30 bbls of MudPush at 12.5 ppg, pumped at 3.5 bpm at 640 psi, pumped 46.6 bbls (223 sxs) of Class "G" GasBlok cmt with celloflakes and add's. at 15.8 ppg and 1.17 yield, pumped at 3.5 bpm at 545 psi, Casing landed on hanger prior to pumping cement. 2.00 CEMEN PUMP INTRM1 Dropped shut off plug and Dowell pumped 10 bbls Fresh water, turned over to rig and rig displaced cmt with 11.9 ppg mud, Displaced at an ave rate of 3.5 bpm, init circ press, 400 psi, saw dart go thru stage tool, had 50 psi increase, cont to displace cmt at 3.5 bpm until 1 0 bbls MudPUSH outside shoe, Then slowed rate to 3.0 bpm, Initial pressure at 3.0 bpm 525 psi, final circ press 625 psi (Had 100 psi lift pressure), bumped plug to 1200 psi wI total of 363.8 bbls mud and 10 bbls fresh water, held for 5 min, Check floats- OK, CIP at 02:00 hrs 2/3/04, Had full returns thru out job, Calc. TOC @ 9,150', Pressured up to 3,200 psi and opened stage tool at 6,198'. Wait on first stage cmt to set, Circ at rate of 2.5 bpm @ 230 psi with no losses. 2/1/2004 21 :30 - 00:00 2.50 CASE CIRC INTRM1 2/2/2004 00:00 - 00:30 0.50 CASE CIRC INTRM1 00:30 - 13:30 13.00 CASE RUNC INTRM1 13:30 - 18:30 5.00 CASE RUNC INTRM1 18:30 - 21 :00 2.50 CEMEN CIRC INTRM1 21 :00 - 21 :30 0.50 WAlTON EQIP INTRM1 21 :30 - 22:45 1.25 CEMEN CIRC INTRM1 22:45 - 00:00 2/3/2004 00:00 - 02:00 02:00 - 08:00 6.00 WAlTON CMT INTRM1 08:00 - 09:45 1.75 WAlTON CMT INTRM1 09:45 - 11 :45 2.00 CEMEN PUMP INTRM1 Stage rate up to 3.5 bpm @ 545 psi, no losses. Hold Pre-job meeting & batch mix cement slurry. Pump 2nd Stage cement job wI Dowell. Pumped 10 bbls CW-100, Test lines to 4000 psi, Pump 20 bbls CW-100, 30 bbls Mud Push @ 12.5 ppg., 37 bbls Class 'G' Gasbloc cement (209 sx) with celloflakes & additives @ 15.8 ppg. Drop closing plug & pump 10 bbls H20. Displace cement with rig pumps @ 3.5 bpm with no losses thru out job. Bump plug, close stage tool. Tool shifted closed @ 1200 psi. Check tool, OK 1.50 CEMEN RURD INTRM1 Rig down Dowell cement equipment, Landing joint. Clear floor of casing tools. Change out bails. 11:45 -13:15 Printed: 3/16/2004 2:57: 19 PM e Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 2/312004 13:15 - 14:30 1.25 CASE OTHR INTRM1 Install FMC Gen V 7" pack off & test same to 5000 psi 110 mins. 14:30 - 22:30 8.00 DRILL PULD INTRM1 Rig up to lay down 5" DP from derrick. Install mousehole. Lay down DP from derrick. UD NMCSP DP 22:30 - 00:00 1.50 RIGMNT RSRV INTRM1 Slip & Cut Drilling Line. 2/4/2004 00:00 - 01 :30 1.50 WELCT EaRP INTRM1 Change out saver sub to 4" XT-39, Change out bell guide & grabbers on top drive. 01 :30 - 03:30 2.00 WELCT INTRM1 Change out rams; upper rams to 3-1/2" X 6" variables bottoms to 4" solid body rams. Move double annulus valve to upper annulus. 03:30 - 04:00 0.50 WELCT INTRM1 Install test plug & rig up test joint. 04:00 - 07:30 3.50 WELCT INTRM1 Test BOPE to 250 psi low & 5000 psi high. Tested annular to 250 psi & 3500 psi. Perform accumulator test. Record BOPE test on chart. John Spaulding, AOGCC rep. waived witnessing the test. 07:30 - 08:00 0.50 WELCT EaRP INTRM1 Install wear bushing. RID Test joint. RILDS 08:00 - 08:30 0.50 RIGMNT RSRV INTRM1 Service Top Drive & Swivel packing (loose). 08:30 - 09:00 0.50 DRILL PULD INTRM1 P/U 6 joints 4" DP & stand back in derrick. 09:00 - 11 :30 2.50 DRILL PULD INTRM1 M/U BHA #3, orient tools. Hold PJSM on RA sources. Install RA sources. 11 :30 - 12:45 1.25 DRILL PULD INTRM1 RIH w/ BHA #3, P/U 4" HWDP to 1114'. 12:45 - 13:15 0.50 DRILL DEaT INTRM1 Pulse Test MWD/LWD tools. 13:15 - 18:00 4.75 DRILL TRIP INTRM1 RIH P/U 4" DP( Fill pipe @ 3565') to 6066'. 18:00 - 19:15 1.25 CEMEN DSTG INTRM1 Wash fl 6066' to 6194'. Cement @ 6194'-6198'. Tag stage tool @ 6198'. Drill out stage collar & wash to 6310'. 19:15 - 20:00 0.75 DRILL OTHR INTRM1 Rig up & test stage collar & casing to 3000 psi 15 min. Rig down equipment. 20:00 - 23:30 3.50 DRILL TRIP INTRM1 RIH continue Picking up 4" DP. (Break circ @ 8584') to 9805'. Tag cement @ 9805' 23:30 - 00:00 0.50 CEMEN COUT INTRM1 Drill cement from 9805' to 9888' 2/5/2004 00:00 - 00:15 0.25 CEMEN COUT INTRM1 Drill cement fl 9888' to 9926' 00:15 - 01:15 1.00 CEMEN CIRC INTRM1 Circ out cement & cement contaminated mud for casing test. 01:15 - 02:15 1.00 CASE MIT INTRM1 RlU equipment, Perform casing test. 3500 psi 130 minutes (lost 50 psi) Record test on chart. RID equipment. 02:15 - 06:00 3.75 CEMEN DSHO INTRM1 Drill out cement, landing collar, float equipment. Tag float collar @ 9978', shoe @ 10065'. Clean out rathole to 10074' 06:00 - 06:15 0.25 DRILL DRLG INTRM1 Drilling 6-1/8" hole f/ 10074' to 10094'. 06:15 - 07:15 1.00 DRILL CIRC INTRM1 Pump sweep & displace cement contaminated mud with re-conditioned 10.2 LSND mud. 07:15 - 08:00 0.75 DRILL LOT INTRM1 Perform FIT to 12.6 EMW. Hole depth 10094' MD, 5289' TVD. Shoe depth 10065' MD, 5276' TVD, Mud weight 10.2 ppg, 650 psi. Record on chart. 08:00 - 08:45 0.75 DRILL OTHR PROD Perform PWD baseline test. 08:45 - 00:00 15.25 DRILL DRLG PROD Drilling 6-1/8' hole f/1 0094' to 10945' (5661' TVD), ADT =11.6 hrs. PIU wt, 173k, SIO wt. 74k, ROT wt 105k, Torque 14k on bttm, 15k off bttm. 2/6/2004 00:00 - 01 :30 1.50 DRILL CIRC PROD Pump weighted sweep & circulate hole clean. 270 gpm, 2650 psi. Max ECD 12.85. 01 :30 - 01 :45 0.25 DRILL OBSV PROD Monitor well, static 01 :45 - 03:00 1.25 DRILL WIPR PROD Backream to 7" shoe wI drilling rates. 8 bbls over calculated displacement. 03:00 - 03:15 0.25 DRILL OBSV PROD Monitor well @ shoe, well static. 03:15 - 04:00 0.75 DRILL WIPR PROD RIH to bottom, precautionary ream 80' to bottom. No fill. S.O. wt 70k 04:00 - 06:30 2.50 DRILL CIRC PROD Circulate bottoms up, max gas 103 units. Pump weighted sweep, max ECD 12.75. Add lube-tex to suction pit (4.5%) displace same to bit. 06:30 - 08:00 1.50 DRILL TRIP PROD Monitor well, backream out to shoe. displace lube-tex to surface. 3 bbls Printed: 3/16/2004 2:57: 19 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 2/612004 06:30 - 08:00 1.50 DRILL TRIP PROD over calculated displacement. 08:00 - 08:30 0.50 DRILL OBSV PROD Monitor well static. Pump dry job, UD 1 joint DP to change break. Drop 2-3/8" rabbit on stand #95. 08:30 - 10:00 1.50 RIGMNT RGRP PROD Rig black out. Electrical power failure. Digital panel meter selector switch failed. Blew fuses for generator exciter circuits. Trouble shoot problem & replace fuses. 10:00 - 14:30 4.50 DRILL TRIP PROD POOH on trip tank. 12 bbls over calculated displacement. 14:30 - 16:00 1.50 DRILL PULD PROD Lay down BHA, Remove R.A sources, Download LWD info, continue to lay down BHA. 16:00 - 17:30 1.50 LOG PULD PROD Rig up Schlumberger wire line unit. 17:30 - 00:00 6.50 LOG ELOG PROD Run US IT log with SWS. 217/2004 00:00 - 01 :00 1.00 LOG PULD PROD RID Schlumberger E-line unit & lubricator. 01 :00 - 02:00 1.00 CASE OTHR PROD Rig up Doyon casing equipment. Hold PJSM 02:00 - 04:00 2.00 CASE PULR PROD PIU 3-1/2" SLHT liner. 04:00 - 04:45 0.75 CASE PULR PROD M/U SSE, Liner hanger, packer, Prepare same. RID casing equipment. 04:45 - 05:00 0.25 CASE PULR PROD Cross over to 4" DP. PIU 1 st stand& circ 1 liner volume. 3 bpm- 190 psi. Up wt. 46k, Dn wt. 40k 05:00 - 11 :15 6.25 CASE RUNL PROD RIH w/ Liner. fill pipe every 10 stands. (P/U 2 joints DP) to shoe. 11:15-14:00 2.75 CASE CIRC PROD Circulate & Condition mud @ 10,005'. PIU wt 153k, Dn wt. 73k, Torque 8k. P/U wt. w/ Rotating 11 Ok, Dn wt w/ rot.,85 Rot wt, 95k 14:00 - 15:30 1.50 CASE RUNL PROD RIH wI Liner to 10945'. No problems. 15:30 - 19:30 4.00 CASE CIRC PROD Circulate, stage pumps up to 4 bpm w/ no losses. Rotate & recip. pipe w/ circ. PIU wt 180k, Dn wt. 70k. Torque 10k. Hold PJSM & batch mix cement. 19:30 - 20:00 0.50 CEMEN PUMP PROD Cement wI Dowell. Pump 10 bbls CW-100, Test lines to 4500 psi., Pump 20 bbls CW-100, 30 bbls Mudpush XL @ 11.5 ppg, 51.7 bbls class 'G' cement w/ Additives @ 15.8 ppg. Shut down wash lines to floor. Drop plug. 20:00 - 21 :00 1.00 CEMEN DISP PROD Dipslace cement w/ seawater (Dowell) @ 4 bpm. Rotate & Recip. liner until last 15 bbls of displacement. No Losses. Bump plug wI 112.8 bbls. (Pressure inc @ 105 bbls). CIP @ 21:00 21 :00 - 21 :30 0.50 CEMEN OTHR PROD Pressure up set hanger, Liner top packer, test same. Release from liner. Liner top @ 9893' Shoe @ 10943' 21 :30 - 23:00 1.50 CASE CIRC PROD Displace wI seawater. Had 7 bbls cement returns to surface. 23:00 - 00:00 1.00 DRILL PULD PROD POOH UD 4" DP. 2/8/2004 00:00 - 05:30 5.50 DRILL PULD PROD Continue UD 4" DP. UD liner running tool. 05:30 - 06:00 0.50 DRILL PULD PROD PIU Top drive cement head & Break 10' pup joint, UD Top Drive head. 06:00 - 06:45 0.75 DRILL PULD PROD RIH wI 4" DP & 4" HWDP from Derrick, UD same 06:45 - 07:00 0.25 DRILL OTHR PROD Pull wear bushing. 07:00 - 07:30 0.50 DRILL OTHR PROD Change out handling tools from 4" to 5" 07:30 - 10:45 3.25 DRILL PULD PROD UD 10 Stds 5" HWDP, jars, 25 stds 5" DP from derrick. 10:45 - 11 :45 1.00 CMPL TN OTHR CMPL TN Rig up Doyon tubing equipment 11 :45 - 12:30 0.75 CMPLTN OTHR CMPL TN Prepare completion Assy. in pipeshed. Hold PJSM. 12:30 - 20:30 8.00 CMPL TN PULD CMPL TN PIU completion equipment & run 4-1/2" Tubing as per plan. 20:30 - 22:00 1.50 CMPL TN SOHO CMPL TN Locate seal bore wI pump pressure, No-Go out tubing. Space out & make up tubing hanger. 22:00 - 00:00 2.00 CMPL TN CIRC CMPL TN Displace well wI clean seawater. 2/9/2004 00:00 - 01 :00 1.00 CMPLTN CIRC CMPL TN Displace well to seawater, 3 bpm @170 psi 01 :00 - 02:00 1.00 CMPL TN RUNT CMPL TN Re-enter seal assembly, land tubing. RILDS. 02:00 - 05:00 3.00 CMPL TN DEQT CMPL TN Tested tubing to 3500 psi for 30 minutes. OK on chart. Bled tubing to 1200 psi. Pressure up annulus to 3500 psi for 30 minutes OK on chart. Printed: 3/16/2004 2:57: 19 PM Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 2P-419 2P-419 ROT - DRILLING n1334@ppco.com Doyon 141 Start: 1/20/2004 Rig Release: 2/9/2004 Rig Number: Spud Date: 1/21/2004 End: 2/9/2004 Group: 2/9/2004 02:00 - 05:00 3.00 CMPL TN DEQT CMPL TN 05:00 - 06:00 1.00 CMPL TN RURD CMPL TN 06:00 - 08:30 2.50 CMPL TN NUND CMPL TN 08:30 - 11 :00 2.50 CMPL TN NUND CMPL TN 11 :00 - 14:00 3.00 CMPL TN FRZP CMPL TN 14:00 - 15:00 1.00 CMPL TN NUND CMPL TN Bled off tubing pressure and sheared DCR valve. Pulllandin9 joint and install two way check. Change out bottom pipe rams from 4" to 5". Nipple down 135/8" BOPE. Nipple up FMC tree. Test tree and void to 5000 psi, good test. Pull TWC. Freeze protect 4.5" x 7" annulas with 75 barrels of diesel. U-tube diesel to 4.5" tubing. Diesel at 2200'. Set BPV and secure well. Installed all guages on tree. Rig released at 15:00 hrs on 2/9/2004. Printed: 3/16/2004 2:57:19 PM e 2P-419 Operations Summary e Date Summary 02/24/04 ASSISTED APC CREW PULL BPV. DRIFT TBG TO 10,834' RKB. IN PROGRESS.D [Tag, GLV] 02/27/04 WEATHER DELAYED START. DRIFTED TBG WITH 20' DUMMY GUN TO 10,822' RKB. PULLED DCK @ 9776' RKB & REPLACED WITH DV. TESTED TBG & CSG 2500 PSI,OK.D [Tag, GLV] 03/06/04 RAN SCMT LOG: EXCELLENT BOND FROM 10803' TO 9938' -- PERFORATED: 10644'-10664',6 SPF PJ -- TAGGED TD AT 10814'. WILL CONTINUE TO ADD PERFS #' IN THE AM.D [Perf] 03/07/04 DUE TO ADVERSE WEATHER CONDITIONS, CONDUCTORLlNE WAS ONLY ABLE TO PERFORATE 10530' - 10570', WITH 2 1/2" HC/DP (.36" EHD AND 27" PENETRATION) 6 SPF POWERJET GUNS @ 60 DEG PHASING. 0 [Perf] 03/08/04 PERFORATED: 10250'-10290' AND 10510'-10530', 6 SPF POWERJET.D ./ [Perf] 03/09/04 PERFORATED: 10216' - 10236', 6 SPF POWERJET -- SBHP AT 10053'= 2168.0 PSIA, J TEMP= 133.3 DEGF II SBHP AT 10253'= 2206.7 PSIA, TEMP= 137.4 DEGF // SBHP AT 10587'=2272.8 PSIA, TEMP= 138.4 DEGF 03/14/04 MITIA initial State Witnessed (John Crisp) - PassedD [ANN COM ISSUES, WH Maintenance] e e ConocoPhillips Alaska, Inc. KRU 2P-419 2P;;41Q ...< ...;.·i·;.......;;.·,·.........."..··...· ·".............;.i···.···. i ...i.·..·..·..·.... API: 501032048300 Well TVDe: PROD Anale (cj) TS: dea (cj) TUBING SSSV Type: NIPPLE Orig Angle @ TD: deg@ (0-4840, ComDletion: 00:4.500, Annular Fluid: Last W/O: Rev Reason: NEW SCHEMATIC 10:3.958) SURFACE Reference Loa: 28' RKB Ref Loa Date: Last UDdate: 2/27/2004 (0-3287, Last Taa: TD: 10943 ftKB 00:9.625, Last Taa Date: Max Hole Anale: Odea(cj) Wt:40.00) ,. , ". ··,.....·....;...;}i ...;", i;i iiii}'·.· } i}.i DescriDtion Size TaD Bottam TVD Wt Grade Thread TUBING CONDUCTOR 16.000 0 108 108 62.50 H-40 WELDED (4840-9946, SURFACE 9.625 0 3287 3287 40.00 L-80 BTC 00:4.500, PRODUCTION 7.000 0 10065 10065 26.00 L-80 BTC-MOD 10:3.958) LINER 3.500 9893 10943 10943 9.30 L-80 SLHT 'ROOUCTION '} i; }.' iii ...,......,.... ·.'·i.·.·i< (0-10065, Size I TaD 1 Bottom TVD Wt Grade I Thread 00:7.000, Wt:26.00) 4.500 I 0 I 4840 4840 12.60 L-80 1 NSCT 4.500 1 4840 1 9946 9946 12.60 L-80 1 IBT -MOD ·.·....··.......".i·'..i' ······.··.i ....··i;..;.··. " .i.i. .......... ·.··.·····..··ii·.·. ii i St MD I TVD I Man Man Type V Mfr I VType I VOD Latch Port 1 TRO Date Vlv Mfr Run Cmnt 1 97761 97761 CAMCO KBG-2 I DMY I 1.0 BEK-5 0.000 I 0 2/8/2004 xo ii .·........i·.··i ......·.·.;ii ....... i' ............................ i.i i< i ii i<. (9830-9831, DeDth TVD Tvee DescriDtion ID 00:5.200) 23 23 HANGER 4.5" FMC GEN V TUBING HANGER 4.500 505 505 NIP CAMCO LANDING 'DB' NIPPLE 3.875 9830 9830 XO 2.991 9879 9879 SLEEVE BAKER CMU DS PROFILE 2.812 9895 9895 NIP CAMCO 'D' NIPPLE 2.750 9908 9908 LOCATOR BAKER G-22 LOCATOR 3.000 SLEEVE 9909 9909 SEAL BAKER SEAL ASSEMBLY 80-40 GBH-22 3.000 (9879-9880, 9946 9946 SHOE BAKER 1/2 MULESHOE 3.000 00:4.500) Oth'ètll lûâšiÊ··alÎÌöliêtôDI·LINERilEWELR'Y ................................ ..................... Depth TVD Type Description ID 9893 9893 PACKER BAKER ZXP HR LINER TOP ISOLATION PACKER 5.000 9912 9912 NIP RS PACKOFF SEAL NIPPLE 4.250 9915 9915 HANGER BAKER FLEXLOCK LINER HANGER 5.000 9925 9925 SBE BAKER 80-40 SEAL BORE EXTENSION 4.000 PACKER 9943 9943 BUSHING XO BUSHING 3.000 (9893-9894, 10941 10941 SHOE 2.992 00:7.000) ....... ......... .... ............... i iiii i.' Date I Note 2/8/20041 TREE: FMC 1 GEN VI FMC 4-1/16" / 5 K TREE CAP CONNECTION: OTIS 9" NIP (9895-9896, 00:4.500) LINER (9893-10943, 00:3.500, Wt:9.30) SHOE IJ (9946-9947, 00:4.000) .... .... y ConocoPhillips ConocoPhillips Alas~c.,slot #419 Drill Site 2P, Meltwater,North Slope, Alaska wellb.419 Well path: MWD wI Multi-Correction<0-10945'> Date Printed: 7-May-2004 ,&¡. BAKER HUGHES INTEQ True I Field :ater I EaStin~ 41964 2388 INorth~ 698914660 I~~~ ...< .. I_ðl""mont I - - R!~~ERJCANDA~~'927 d~m ·TO>e All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 RKB 252.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 195.68 degrees Bottom hole distance is 8079.00 Feet on azimuth 197.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated d.~ '-t - 0\, y ConocoPhillips ConocoPhillips Alaslnc.,Slot #419 Drill Site 2P, Meltwater,North Slope, Alaska well.: 419 Wellpath: MWD wI Multi-Correction<O-10945'> Date Printed: 7-May-2004 "~i. BAKER HUGHES INTEQ WeUDath (Grid) ReDort . MD[ft] Inc[deg] Azi[deg] TVD[ft] Station Station Dogleg SeveritJ Vertical Easting Northing Position(Y\ PositionlX\ Sectionrftl nnn nnn nnn 0.00 nnnN nnn~ n nn 0.00 040404 1 nA n'l n? 1nA nn nnn nnn 1nA nn OOON OOO~ 000 000 AAA1nA n~ .n? 175.40 1.12 203.08 175.40 0.61S 0.26W 1.66 0.65 444107.77 5868987.42 ?11 ?n 101'; ?OO q? 211.19 1 ?d~ O!'i1W O?O 1.33 444107.!'i1 '101 04. 177 1$10704 '10100 'IdO~ OR'IW o q!'i 'I !'i0 444107.1R 390.55 2.84 169.09 390.44 6.96S 0.43W 1.30 6.82 444107.56 5868981.06 d7q 7R 04 041'; 1!'i7 '17 479.49 1? 'I'I~ 1 'I'I~ 1 qq 11 !'i? 44410q ?7 !'i7? 10 7.1';!'i 1 !'i?d!'i !'i71?R 21.10~ !'i!'i!'iF :-I.!'iO 1R.R1 040404113.4:-1 nn 662.79 9.88 151.19 660.90 33.27S 12.09E 2.47 28.76 444119.88 5868954.67 7!'i'l qO 10 '1$1 1!'i1 Rq 7!'i0!'iq 047 'II';~ 1q 7'1~ 0!'i7 dO ?I'; 444127..41 ß4!'i04. 11.8? 15:-111 ß400:-l 62.92S ?7.82E 1.60 5:-1.07 4441:-\5.'IQ "ARAQ?4.90 934.27 13.93 153.25 927.01 80.67S 36.79E 2.36 67.72 444144.22 5868907.09 10?4.40 11'; 01 15:-14:-1 1014.0R 1 01 4R~ 472:-1E ?:-I1 ß4 q:-l 4441 <;A "1 1122.2:-1 20.80 154.85 1106.87 1?q ?R~ I';nl';l';~ 4.92 108.08 4441677'1 1214.99 25.31 158.44 1192.21 162.65S 74.95E 5.09 136.34 444181.78 5868824.84 1 'lOR 74 ?750 15q1q 127617 ?n1 ,,~c:: 9000E ?:-I6 11';q70 44419R "" 1An~ d!'i 30.35 159.33 1359.06 ?44 'II';~ 1nl'; ??~ :-1.01 206.56 A A......... AC 1495.90 36.14 159.58 1436.35 291.80S 123.99E 6.26 247.43 444229.87 5868695.34 15RR RR 4070 16000 150916 -:tð.l';nnc:: 104<1 QA~ 4.91 294.23 IAA'HO 041 "ARAM1 nn 11';Rn R1 d!'i <II'; 160.65 1576.36 dn!'i n7~ 1 R!'i 04.~ 5.09 345.39 t;RI';Rt;R1 7q 1774.04 50.40 161.87 1638.86 470.55S 187.22E 5.49 402.44 444291.78 5868516.16 1 R674? 5521 16090 1695:-10 <;Ai n1C:: 210.98E 5.22 46:-1.86 1 Qt;R Q" t;1'; d? 160.27 1746.73 1';1? d?~ ?'II'; 1t;~ 1.44 525.80 ~------ ,~ 2051.96 59.44 159.72 1796.11 686.47S 263.11E 3.29 589.81 444366.08 5868299.71 2145?4 6:-141 159.56 1840.71 7I';<I.?t;c:: 291.61E 4.26 656.04. IAA'>OA. n1 ·7? ??<l7dR 1';1.81 160.07 1881.71 ß4n Rn~ <I?n.1?~ 0.66 723.00 444421 Q<1 <:t :'''1AA Q7 2327.80 63.92 160.40 1921.50 917.11S 347.54E 0.35 789.06 444448.80 5868068.47 2424.00 64.24 160.44 1963.55 QQR.I';<lC:: 376.54E 0.33 859 70 4 .."7"7...." <:""'7Q"'" 7<: ?t;1t; t;7 1';'1 ?d 160.55 2004.06 1n7R.n4~ dn'l qt;~ 1 in 926.82 444t;04. 04. t;Rl';7qnq 1 t; 2608.20 61.88 160.20 2046.75 1153.47S 431.56E 1.51 993.91 444531.08 5867831.53 ?7nn QA I';? nQ 160.81 2090.32 dt;R Qn~ 0.62 1060.86 <:""'77<:A 1'1 ?7qd n7 1';1 Rt; 1l';n ?7 2134.07 4RR ?7~ o t;7 11?R Ot; ACO t:!c <:A"'7"'7'" AR 2885.99 62.72 159.19 2176.82 1384.49S 514.47E 1.41 1193.93 444612.28 5867599.93 ?QR1 1 t; 1';<1 ?t; 1 t;q d!'i 2220.05 ,.~~ ~~~ <;.404 dn~ n 1';1 1262.20 444641 1';'1 <:A"'7<:?n ,11 'In7? 7? R4 404 15q RR ??RO 41 57'1 11 ~ 1 'I? 1'1?R5q 4441';I';q77 <:AR7AA~. HI 3165.67 64.77 159.85 2300.27 1619.60S 602.17E 0.40 1396.58 444698.24 5867364.21 'I?1R -:tð. Rt; 1? 1RO ?7 ')<\?? 5R 't:!t:!A ACC' R1R 44~ OClR 14:-1t; '17 ,1,1,171,1 1A Cot:!"7'>'" ?A :-1:-111:-1'1 6475 1600:-1 2361C17 17,1<1 RA~- R47.04E 0.46 150:-1.92 .- ". 3405.59 64.74 161.50 2402.19 1824.17S 675.13E 1.41 1573.82 444769.69 5867159.13 'I4qR 04. 6:-1'1R 16456 244265 ~~n 6C1C1.40E '1:-1:-1 1R4'17C1 4447M ~A A7 ~"Q1 1 ~ 62.66 16670 2484.90 1Qß4 n1~ 71Q QQ~ 2.18 1715.59 44481"1 '17 Q" 3684.49 61.77 171.54 2528.44 2065.08S 735.59E 4.68 1789.43 444828.37 5866917.80 :-I776.CI? 61C16 174.70 2572.04 ?1dt;.QQ;::- 745.35E :-1.02 1864.69 4dAA~7 <;.4 ,,'> <lRI';R 7t; I';? n1 178.06 2615.18 ???I';.RR~ 7t;n41';~ <I ?'I 1941.18 44dß4? nl'; q1 3962.26 62.66 181.05 2658.60 2309.68S 751.10E 2.92 2020.73 444842.09 5866673.12 4055.40 6272 183.43 2701.34 ?<lQ?<l7C:: 747.86E 2.27 2101.22 44dR<lR ?t; At:! 041047 QA 1';171 186.28 2744.50 ?A7'> Q7C 7dn qd~ ? q'l 2181.65 dddR<ln 7'1 4240.94 61.24 188.89 2788.90 2554.92S 730.17E 2.52 2262.50 444819.36 5866428.06 A~~~ An 6178 192.58 2833.21 ?"''><: n"c 7104 ~~ :-1.54 234:-1.79 dAAAn<l t;7 dd?1'; Qn 1';17n 195.18 2877.29 ?71d I';R~ I';qt;?q~ ? 041'; 2425.75 040404 7R<I <I? ~~ 4519.74 62.11 198.36 2921.03 2793.08S 671.66E 3.05 2507.62 444759.12 5866190.36 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Doyon #141 RKB 252.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 195.68 degrees Bottom hole distance is 8079.00 Feet on azimuth 197.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated Conoc;p.,illips ConocoPhillips Alasfnc.,Slot #419 Drill Site 2P, Meltwater,North Slope, Alaska well. 419 Well path: MWD wI Multi-Correction<0-10945'> Date Printed: 7-May-2004 ,&¡. BAKER HUGHES INTEQ WellDath JGrid) Report MD[ft] Inc[deg] Azi[deg] TVD[ft] Station Station Dogleg Severi!) Vertical Easting Northing Position(Y) Position()() Sectionfftl df;1? In f;? da 201.65 2963.93 ?Rf;a R<;~ 643.71E 3.18 2589.08 ddd7~O f;1 R1 d7M R<; f;? d~ ?Of; 1<1 ~OOf; R7 ?QA" n7e:: 610.39E 4.29 2670.51 <14d1;91; 7~ RA 4798.92 63.50 209.41 3049.64 3019.19S 571.34E 3.30 2752.42 444657.15 5865965.02 dRaO 07 M d<; ?10 <;1 3089.63 3090.158 530.43E 1.50 2831.79 dddl;1<; 7~ <17 d97<; <;7 Mid ?11 7~ ~1?1; 71 3156.108 490.62E 1.34 2906.05 d<14<;7<; d~ ''/ 5069.13 64.13 211.05 3167.53 3227.96S 446.77E 0.65 2987.09 444531.06 5865757.18 <;11;? R<; f;<; dO ?11 ~? 3207.49 ~~oo d9~ 402.87E 1.38 3068.78 ddddRI; M <;?<;I; 1 R 1;1; I\? ?1?41 ~?4<;.RR <I<I7? 7<1e:: 357.96E 1.25 3150.47 444<141 ?O 5348.94 65.84 212.84 3283.71 3444.06S 312.30E 0.47 3231.49 444395.02 5865542.10 <;441 41; 1;<; ?I; ?1? ?<; ~~?? 01 3515.06S 266.99E 0.85 3312.09 444349.20 <;1'11;<;471 44 <;<;~ ~7 M.4<; 21?~A ~~I;14A ~<;RI;.14S ???O~F 01'11'1 3392.68 444303.72 5627.25 65.10 211.52 3401.07 3657.43S 177.57E 1.09 3473.33 444258.75 5865329.74 <;7?0 ?O 1;<; 1'17 ?1??<; ~~91;~ ~7?9?4S 1~? 90F 1.09 3554.54 444?1~<;<; <;1'11217 1;<;6~ 211.02 ~7741 <lRnO f;~~ 88.92E 12<; 3635.16 444169.05 5904.63 65.01 212.08 3516.02 3872.23S 44.96E 1.24 3715.97 444124.57 5865115.95 <;991;4~ M ~? ?11 ?A ~<;<;<; ~O <1M? R<le:: 1 ~AF 109 ~79<;n AAAnRn A a 6090 12 64?? 21091 ~<;9<;97 401<;.10S 4221W 0~7 3877.09 dAAO<lf; ~7 6182.72 66.34 212.35 3634.70 4086.71S 86.32W 2.69 3957.96 443991.74 5864902.45 6?74 M 1;<; 94 211?A ~67191; 41<;R~OS ,~^ ~A" 11 <; 4mRA9 AA <lMf; Rn <;RMR~ 1 ?O 6~67 .26 6<;A~ 212.32 ~709.72 A ??a aa~ ,~'" ",.. 1.0~ 4119.92 dd~a01 R~ ,,'" 6461.38 65.39 212.30 3748.59 4302.44S 221.00W 0.47 4202.06 443855.49 5864687.74 6<;<;4 1;9 1;<; 0<; 21?<;0 ~7A7 70 A<l7<1 a7~ ?f;f; Anw 041 42A~ 19 AA <lRna "R 6646~ 644<; 211.47 ~A26.79 AA.A.A ?7~ ~10 ~1W 1.21 4362.75 443765.16 6738.81 63.78 211.40 3867.16 4515.26S 353.69W 0.73 4442.82 443721.26 5864475.92 6A~~ 1 A 6411'1 21241 ~90A<;6 4AA72<;S ~9A.<;1W 10<; 452424 443675.91 5864404.27 6924.64 6524 21173 3947.63 4657.328 442.42W 1.34 4603.58 443631.50 ",,,aA..,.., "'.., 7019.11 64.85 211.98 3987.49 4730.07S 487.62W 0.48 4685.83 443585.77 5864262.12 7111.1<; 6<;~1 2121~ 4026.?7 ARno R?~ "<Ii a?w O.<;? 4765.92 AA <I<;An a" 5864191.71 7205.51 66.07 212.53 4065.12 A"~'" A"" 577.91W 0.89 4848.31 ,..., '''A <;RM 11 9.~9 7297.59 65.46 212.25 4102.91 4944.38S 622.89W 0.72 4928.72 443448.94 5864048.83 7~90A7 64 6<; 211.90 41422<; "n1f; O<;~ f;f;7 Rnw 09~ 5009.86 dA't40~.51 7 dR~ O? f;~ 7d ?1? ?~ 4182.37 <;ORf; ~<;~ 711.84W 1.04 5089.45 7575.57 64.30 212.38 4222.91 5156.67S 756.31W 0.62 5169.17 443313.99 5863837.55 7f;f;7 Ra 65.22 212.65 4262.27 801.19W 1.03 5249.10 A..,,,,a,, "''' A7 771;1 M M 41 ?1? 4~ 4~O? 17 RA~ R<lIAI 0.89 5330.29 A..,"''''''' A. 7853.94 64.85 212.88 4341.72 5368.82S 891.83W 0.65 5410.05 443176.93 5863626.42 794R 0<; 1;<; ?R ?1~ M 4~R 1 ~9 "'A'" A"'C- a<lR ?~IAI 0.48 5491.54 1~ AMOA7 64 7<; 21~06 44?0 1;0 9M14W 0<;7 <;<;71M ",n"''''An "^ 8134.21 63.74 211.75 4461.16 5581.91S 1029.19W 1.66 5652.34 443038.01 5863414.36 A??7 n 64 ?1 ?n07 4<;01 9~ 1n7<1 MIAI 1.37 5732.30 <;A6~~4.21 A~1972 6<;01 214.~ 4<;41 6~ <;7?1.98S 1120.~6W 1.<;1 5811.M ,,,")aM:: D'> "''''''''''''~A ^~ 8412.39 64.36 213.58 4581.26 5791.46S 1167.16W 1.02 5891.38 442898.53 5863205.85 A<;0<;.~7 6<; Ai 2n.A<; 46?04? "R~ 1 f;n~ 121~96W 1.<;1'1 597156 442851.21 5863136.06 8598.14 64.79 213.67 465919 <;a<l1 f;7~ 1260.80W 1.11 6051.68 442803.87 ~^^^^^^ ..,A 8691.52 64.89 213.06 4698.89 6002.26S 1307.29W 0.60 6132.21 442756.87 5862996.10 A7M?6 6<;64 21226 47~7.69 f;n7<1 1R~ n<;2.74W 1.n 6212.77 442710.90 "'O"'^'"..''' ,,<I 887666 6496 213.11 4776~1 1~aR 07\N 111 6293.04 ",,,a",,,,,,,,, "'''' 8968.33 65.11 212.90 4815.00 6213.52S 1443.34W 0.26 6372.38 442619.29 5862785.87 906?9~ 1;<; 64 212<;0 41'1<;441 1 ARa RmAl 061'1 64<;4 61 5862713.85 9155.51 6<;10 212.19 4893.00 1 <;~d R?W 066 6535.23 "D~?~A <I na 9245.83 65.57 211.91 4930.69 6426.56S 1578.38W 0.59 6613.98 442482.70 5862573.85 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 RKB 252.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 195.68 degrees Bottom hole distance is 8079.00 Feet on azimuth 197.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated Conoc~illips ConocoPhillips Alas!nc.,slot #419 Drill Site 2P, Meltwater,North Slope, Alaska well.: 419 Well path: MWD wI Multi-Correction<0-10945'> Date Printed: 7-May-2004 ,&¡. BAKER HUGHES INTEQ W.ell MD[ft] EåSting Northing 442344.30 5862359.59 5862147.58 7651.53S 441687.68 5861354.80 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and.TVD's are from Rig (Doyon #141 RKB 252.00 above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 195.68 degrees Bottom hole distance is 8079.00 Feet on azimuth 197.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated y ConocoPhillips ConocoPhillips Alas!nC.,Slot #419 Drill Site 2P, Meltwater,North Slope, Alaska . Wellbore: 419 Wellpath: MWD wI Multi-Correction<0-10945'> Date Printed: 7-May-2004 ,&¡. BAKER MUGHU INTEQ 7712.68S s All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Doyon #141 RKB 252.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 195.68 degrees Bottom hole distance is 8079.00 Feet on azimuth 197.32 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated Schlumberger NO. 3131 Schlumberger -DCS 2525 Gambell Street, Suite 400 Company: Alaska Oil & Gas Cons Anchorage, AK 99503-2838 Attn: Lisa Weepie A TTN: Beth 333 West 7th Ave, Suite Anchorage, AK 99501 Field: Kuparuk Well Job# Log Description Date BL Color CD 3F-19AXt: '../-OiL 10696856 PERF RECORD & SBHP 03/10/0 1 2P-419"""" ~ ! '"7 10696852 PERF RECORD & SBHP 03/06/0 1 2P-449 ;:7(;1... -r::J{ i 10696851 PERF RECORD & SBHP 03/05/0 1 2K-04 fc:x9 - J\ c\ 10696845 PRODUCTION PROFILE 02/28/0 1 2P-419,~n.LI"'';J:7 10696852 SCMT 03/06/0 1 3F-19Ã"90;¡J-(; U 10696856 SCMT 03/10/0 1 ......._-.. --- Wt :'_8r- ~ 'J Ee J '.~ 03/18/04 Comm 100 " e SIGNE~:~C-' (~ ~~"\" C c'-' ~c::- /'\ ~ - . " DATE: -o\~loL/' ~·ph" ¡"'I;?, r.:!:><:; ['"n", Ccmm~11 ,'.<..:>._:,::,;: ~'b ....,....9w \';VU'tiYt ¡~!\J. ,. ;';~¿'-r:me ,-"',-: ~~.iJ HJ, ~~ ~~A Please sign and return one copy of this transmittal to Beth at the above address or fax to (907) 561-8317. Thank you. '--:::, '........, '--- " \:-:) pI\'\ ~ MEMORANDUM . e State of Alaska TO: Alaska Oil and Gas Conservation Commission THRU: Jim Regg 0" 't 31lb/eft P.I. Supervisor I Y1 l John Crisp Petroleum Inspector DATE: Tuesday, March 16,2004 SUBJECT: Mechanical Integrity Tests CONOCOPHILLIPS ALASKA INC 2P-419 KUPARUK RIV U MELT 2P-419 FROM: Src: Inspector NON-CONFIDENTIAL API Well Numbe 50-103-20483-00-00 Insp N mitJCr040315074925 Inspection Date: 3/14/2003 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well: 2P-419 Type Inj. G TVD 5203 IA 1143 3560 3539 3536 P.T. 2040170 Type'test SPT Test psi 1300.75 OA 425 514 492 483 Interval Initial Test P/F Pass Tubing 2450 2450 2450 2450 Notes: No problems witnessed. The Operator wanted to take pressure to 3500 for initial test. Type INJ. Fluid Codes F =FRESH WATER INJ. G=GAS INJ. S=SALT WATER INJ. N=NOT INJECTING Type Test M=Annulus Monitoring P=Standard Pressure Test R=1ntemal Radioactive Tracer Survey A=Temprature Anomaly Surve D=Differential Temprature Test Interval I=Initial Test 4=Four Year Cycle, V=Required by Variance W=Test during WOIkover O=Other (describe in notes) Tuesday, March 16,2004 Page 1 ofl . . FRANK H. MURKOWSKI, GOVERNOR AlfASIiA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Randy Thomas Kuparuk T earn Leader Conoco Phillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: 2P-419 Conoco Phillips Alaska, Inc. Pennit No: 204-017 Surface Location: 888' FNL, 2148' FWL, Sec. 17, T8N, R7E, UM Bottomhole Location: 2014' FSL, 226' FEL, Sec. 19, T8N, R7E, UM Dear Mr. Thomas: Enclosed is the approved application for pennit to drill the above referenced development well. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the pennit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). /~''v'' Sincerely'-/.-._ I () / C....."..__ / I Þ/ - ~. - - / , , ~x /. / ........--- ''ì.2.;7/c...{.-c/ 1..'-¡\7'z::,:/ '--- '------... " -'-"" ;' " ---- / \\ Sarah Palin . \ Chair BY ORDER OF THE COMMISSION DATED this / b day of January, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Conoc~hillips . Post Office Box 100360 Anchorage, Alaska 99510-0360 Randy Thomas Phone (907) 265-6830 Email: Randy.L.Thomas@conocophillips.com January 12, 2004 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Re: Applications for Permit to Drill Meltwater injector well 2P-419 Dear Sir / Madam ConocoPhillips Alaska, Inc. hereby applies for a Permit to Drill onshore injection well 2P-419 in the Bermuda sands of the Meltwater oil pool. Please find attached for the review of the Commission Form 10-401 and the information required by 20 ACC 25.005 for this well. The planned spud date for this well is 01/18/2004. Please note that the target location for this well is identical to that for well 2P-443 which has already received your approval (APD 203-204, API No. 50-103- 20476-00). It has been decided to drill to 2P-443 target from slot number 2P-419 as this allows us to employ a well path that will minimise the risk of encountering gas at a shallow interval as has happened on 2P-447. ConocoPhillips will re-apply for another Permit to Drill for well 2P-443 when a suitable new target for that slot has been identified. If you have any questions or require any further information, please contact Philip Hayden at 265-6481. Sincerely, \'~~~ Randy Thomas Greater Kuparuk Area Drilling Team Leader RECEIVED JAN 1 3 2004 Alaska Oil & Gas Cons. Commission Anchorage ORtGl~\L~L . . ~ltS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: Drill 0 RedrillU 1b. Current Well Class: Exploratory bJ Development Oil Id Multiple Zone 0 Re-entry 0 Stratigraphic Test 0 Service 0 Development Gas 0 Single Zone 0 2. Operator Name: 5. Bond: ~ Blanket U Single Well 11. Well Name and Number: ConocoPhillips Alaska, Inc. Bond No. 59-52-180 2P-419 3. Address: 6. Proposed Depth: 12. Field/Pool(s): '"" Kuparuk River Field P.O. Box 100360 Anchorage, AK 99510-0360 MD: 10849'" TVD: 5612' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: 888' FNL, 2148' FWL, Sec. 17, T8N, R7E, UM/ ¡J P(...-,.AI:K373112/389058 Meltwater Oil Pool Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 2581' FSL, 133' FWL, Sec. 20, T8N, R7E, UM '"' ADL 32092/32409 1/18/2004 Total Depth: 9. Acres in Property: 14. Distance to " Nearest Property: 2699' @ Target 2014' FSL, 226' FEL, Sec. 19, T8N, R7E, UM 5760 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Surface: x- 444108./ y- 5868988 y Zone- 4 (Height above GL): 252 feet Well within Pool: 2P-420 , 20 16. Deviated wells: 17. Anticipated Pressure (see 20 AAC 25.035) Kickoff depth: 250" ft. Maximum Hole Angle: 64.89° v Max. Downhole Pressure: 2106 psig I Max. Surface Pressure: 1493 psig' 18. Casing Program Setting Depth Quantity of Cement Size Specifications Top Bottom c. f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 42" 16" 62.5# H-40 Weld 80 28 28 108 108 ArticCRETE (preinstalled) 12.25" 9.625" 40# L-80 BTC 3264 28 28 3292 2355 365 sx ASLite, 272 sx LiteCRETE tail 8.5" 7" 26# L-80 BTCM 9434 28 28 9462 5023 654 sx of GasBLOK 8.5" 4.5" 12.6# L-80 IBT-M 1387 9462 5023 10849 5612 Included above 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured) Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured) Casing Length Size Cement Volume MD TVD Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): None None 20. Attachments: Filing Fee 0 BOP SketchC! Drilling Programl;J Timev. Depth Plot~ Shallow Hazard Analysis 0 Property Plat 0 Diverter Sketch 0 Seabed Report 0 Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Philip Hayden @ 265-6481 Printed Name R. Thomas Title Kuparuk Team Leader \/1 e,(ò '{ Signature \'_~c:~~ Phone Date '"2,,& ç //¡J) 0 PreDarprl h" Philin h",,,rlpn Commission Use Only Permit to Drill lj API Number: é./¿' Permit Approval See cover letter Number: 2ð -ú17 50- Ie) 3 - 2ú' B3~{)C Date: for other requirements - - Conditions of approval : Samples required o Ye:l~o Mud log required r\ ' ~ U Hydrogen sulfide measures o Yes No Directional survey required . ~œ;OO4 Other: v.. \\ q. <.0."""".....". ~' I.-,l. ,,":, ~Ç()()\)~, \'I\"\~''''''-.;)'N ~~m~s Cons. Commission ç~ - BY ORDER OF Anchoraop ,I J Approved by: ¿-~/----t\ 'n ' / V-- COMMISSIONER THE COMMISSION Date: ( I to 'Or.... ,/ \1 I . ( I - . . . Form 10 401 Revised 3/2003 ORIGINAL Submit In duplicate · .lication for Permit to Drill, We1l2P-419 Revision No.O Saved: 13-Jan-04 Permit It - Meltwater Well #2P-419 Application for Permit to Drill Document MoximizE Well Vglu~ Table of Contents 1. W eJ I Name. ........... ......... ......... ....... ........................ ......... ..... ....... ...... ......... ................ 2 Requirements of 20 AAC 25.005 (f)............. ........ ...... .................... ............ ........................ ........... ...... ....2 2. Location Sum mary ... ........... ....... ..................... .............. ..... ....... ............... ................ 2 Requirements of 20 AAC 25. 005( c)(2) ......... ...... .... .............................. ..... ........................ ......... ............2 Requirements of 20 AAC 25. 050(b)....... .......... ............... ................................... ............ ................... ...... 3 3. Blowout Prevention Equipment Information ......................................................... 3 Requirements of 20 AAC 25. 005( c)(3) ............. .......................... ......... .............. ............ ............. ............ 3 4. Drilling Hazards Information ................................................................................... 3 Requirements of 20 AAC 25.005 (c)(4) ..................................................................................................3 5. Procedure for Conducting Formation Integrity Tests........................................... 4 Requirements of 20 AAC 25.005 (c)(5) .................................................................................................. 4 6. Casing and Cementing .Program............................................................................ 4 Requirements of 20 AAC 25.005(c)(6) ....... ........ ............................. ........ .......... .... ............... .................. 4 7. Diverter System Information ...................................................................................4 Requirements of 20 AAC 25.005(c)(7) ...................... .... ....................................... .......... .... ............. ....... 4 8. Dri II i ng FI u id Program ........ .......... ......................... ......... .......... ....... .......... .......... .... 5 Requirements of 20 AAC 25.005(c)(B) ... ......... ............. ................... .......... ........ ................ ............ ......... 5 Surface Hole Mud Program (extended bentonite) .................................................................................. 5 Production Hole Mud Program (LSND) ....... ......................... ....... .................................... .......... ............. 5 9. Abnormally Pressured Formation Information ......................................................5 Requirements of 20 AAC 25.005 (c)(9) ..................................................................................................5 10. Seismic Analysis ........ ............. ........... .................. ............ ........... ............ ................. 6 Requirements of 20 AAC 25.005 (c)(10) ................................................................................................6 11. Seabed Condition Analysis .....................................................................................6 Requirements of 20 AAC 25.005 (c)(11) ................................................................................................ 6 12. Evidence of ·Bonding ...............................................................................................6 ORIGINAL 2P-419 PERM/T /T.doc Page 1 of 7 Printed: 13-Jan-04 · .ication for Permit to Drill, Well 2P-419 Revision No.O Saved: 13-Jan-04 Requirements of 20 AAC 25.005 (c)(12) ................................................................................................ 6 13. Proposed Drilling Program .....................................................................................6 Requirements of 20 AAC 25.005 (c)(13) ................................................................................................ 6 14. Discussion of Mud and Cuttings Disposal and Annular Disposal....................... 7 Requirements of 20 AAC 25.005 (c)(14) ................................................................................................7 15. Attachments ................. ......... .... .............. ...... ....... ............. .......... ....... ............ .......... 7 Attachment 1 Directional Plan (13 pages) .............................................................................................. 7 Attachment 2 Drilling Hazards Summary (1 page) ................................................................................. 7 Attachment 3 Cement Loads and CemCADE Summary (2 page) ......................................................... 7 Attachment 4 Well Schematics (1 page) ................................................................................................ 7 1. Well Name Requirements of 20 AAC 25.005 (f) Each well must be Identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 MC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this Application is submitted will be designated as 2P-419. 2. Location Summary Requirements of 20 AAC 25.005(c)(2) An application for a Permit to Drill must be accompanied by each of the following Items, except for an item already on file with the commission and identified in the application: (2) a plat identifying the property and the property's owners and showing (A)the coordinates of the proposed location of the well at the surface, at the top of each objective formation and at total depth, referenced to governmental section lines. (8) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth; Location at Surface I NGS Coordinates Northings: 5,868,988 Eastings: 444,108 888' FNL 2148' FWL, Section 17, T8N, R7E, UM I RKB Elevation I 252' AMSL I Pad Elevation I 224' AMSL Location at Top of Productive Interval Bermuda Sand NGS Coordinates Northings: 5,861,912 2581' FSL, 133' FWL, Section 20, T8N, R7E, UM 10 110 Eastings: 442,064 5 298 5046 Location at Total De NGS Coordinates Northings: 5,861,349 Eastings:441,703 2014' FSL 226' FEL Section 19 T8N R7E UM Measured De th RKB: 10 849 Total Vertical De th RKB: 5612 Total Vertical De th 55: 5 360 and ORIGINAL 2P-419 PERM/T IT.doc Page 2 of 7 Printed: 13-Jan-04 · .. 'cation for Permit to Drill, We1l2P-419 Revision No.O Saved: 13-Jan-04 (D) other information required by 20 MC 25.050(b)/ Requirements of 20 AAC 25.050(b) If a well is to be intentionally deviated" the application for a Permit to Drill (Form 10-401) must (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellOOre, including aI/ adjacent wellbores within 200 feet of any portion of the proposed welt Please see Attachment 1: Directional Plan and (2) for all wells witl1ín 200 feet of the proposed wellbore (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail,; or (B) state that the applicant is the only affected owner. The Applicant is the only affected owner. 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) An application for a Permit to Dlill must be accompanied by each of the following items, except for an item already on file with tIle commission and Identified in the application: (3) a diagram and description of the blowout preventIon equipment (BOPE) as required by 20 MC 25.035, 20 MC 25.030 or 20 MC 25.03/; as applicable,; An API 13 5/8" x 5,000 psi BOP stack (RSRRA) will be utilized to drill and complete weIl2P-419. Please see information on the Doyon Rig 141 blowout prevention equipment placed on file with the Commission. 4. Drilling Hazards Information Requirements of 20 AAC 25.005 (c)(4) An application for a Permit to Drill must be accompanied by ead¡ of the following items, except for an item already on file with the commission and identified in the application: (4) information on drilling hazards, including (A) the maximum downhole pressure that may be encountered" criteJia u:.w to determine it, and maximum potential surface pressure based on a methane gradient,· The expected reservoir pressures in the Bermuda sands in the 2P-419 area vary from 0.26 to 0.38 psi/ft, / or 5.1 to 7.2 ppg EMW (equivalent mud weight). These pressures are predicted based on actual bottom hole pressure data from existing wells on the field together with reservoir model forecasts. The maximum potential surface pressure (MPSP) based on the above maximum pressure gradient, a methane gradient (0.11) and the deepest planned vertical depth of the Bermuda sand formation is 1493 psi, calculated as follows: MPSP =(5531 ft)(0.38 - 0.11 psi/ft) =1493 psi 0". (B) data on potential gas zones,; Due to the presence of high annular pressures on some of the Meltwater wells (2P-431, 451 & 438) and v the occurrence of gas in some of the wells drilled to date in the current program there is the risk of encountering a pressured shallow zone. This interval may be encountered through the C-80 formation to the top of the Bermuda. The original high pressures recorded in these annuli were of concern but as can be seen from the following table a series of annular bleeds together with an observed natural decline in pressures have reduced the potential maximum pressure considerably: Oriainal Latest Well Surface Fluid C-80 C-80 Equivalent Surface Fluid C-80 C-80 Equivalent Pressure Level Pressure Gradient (ppq) Pressure Level Pressure Gradient (PDCI) 2P-431 1600 2387 1751 13.85 1200 193 1678 13.27 2P-451 1380 2160 1541 12.23 750 1392 1020 8.10 ORIGINAL 2P-419 PERMIT /T.doc Page 3 of 7 Printed: 13-Jan-04 · .. . lication for Permit to Drill, Well 2P-419 , Revision No.O Saved: 13-Jan-04 I 2P-438 I 879 I 895 I 1245 800 I 768 I 1216 9.83 9.60 Using the latest annular pressures available the highest pressure that would be expected is approximately 1678 psi at 2391 ft ìVD or 13.5 ppg EMW. Most of the previously drilled Meltwater wells have had an FIT/LOT of approximately 16 ppg thus indicating that this pressured interval, should it exist, can be safely controlled with standard well control methods. and (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please see Attachment 2: Drilling Hazards Summary. 5. Procedure for Conducting Formation Integrity Tests Requirements of 20 AAC 25.005 (c)(5) An application for a Permit to DJiII must be accompanied by each of the fol/owing items, except for an item already on file wIth the commission and Identified in the application: (5) a description of the procedure for conducting formation integllty tesls¡ as required under 20 MC 25.030(f); 2P-419 will be completed with 9 5/8" surface casing landed above the C-80 mudstone interval. The casing shoe will be drilled out and a leak off test will be performed in accordance with the "Leak Off Test Procedure" that ConocoPhillips Alaska placed on file with the Commission. 6. Casing and Cementing Program Requirements of 20 AAC 25.005(c)(6) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (6) a complete proposed casing and cementing program as required by 20 AAC 25.030; and a descn'ption of any slotted /inel; pre- perforated liner; or screen to be installed; Casing and Cementing Program I See also Attachment 3: Cement Summary Hole Top Btm Csgffbg Size Weight Length MO/TVO MO/TVO 00 (in) (in) (lb/ft) Grade Connection (ffJ (ft) (ft) Cement Pro.qram 16 42 62.5 H-40 Welded 80 28 / 28 108/108 Cemented to surface with 110 sx ArticCRETE 9 5/8 12 % 40 L-80 BTC 3264 28 / 28 3292/ 2355 Cement to Surface with 365 sx ASLite Lead, 272 sx LiteCRETE Tail 7 8 V2 26 L-80 BTCM 9434 28 / 28 9462 / 5023 Cement Top planned @ 4 V2 8 V2 12.6 L-80 IBTM 1387 9462 / 5023 10849/ 5612 9162' MD/ 4896' ìVD. Cemented w/ 654 sx GasBLOK 7. Diverter System Information Requirements of 20 AAC 25.005(c)(7) An application for a Permit to Drill must be accompanied by each of t/le following items, except for an item already on file with the commission and identified in the application: ORIGINAL 2P-419 PERM/T /T.doc Page 4 of 7 Printed: 13-Jan-04 · .¡Cation for Permit to Drill, Well 2P-419 Revision No.O Saved: 13-Jan-Q4 (7) a diagram and description of the dlverter system as required by 20 MC 25.035, unless this requirement Is waived by the commission under 20 MC 25.035(11)(2); A 21 V4", 2000 psi annular with a 16" diameter diverter line will be the diverter system used in the drilling of 2P-419. Please see diagrams of the Doyon 141 diverter system on file with the Commission. 8. Drilling Fluid Program Requirements of 20 AAC 25.005(c)(B) An application for a Permit to Drill must be accompanied by each of the following item~ except for an Item already on file wIth the commission and Identified in the application: (8) a drilling flUId program, IncludJiJg a diagram and description of the dnlling fluid system, as required by 20 MC 25.033; Drilling will be done with muds having the following properties over the listed intervals: Surface Hole Mud Program (extended bentonite) Spud to Base of Permafrost Base of Permafrost to 95/8" Casin Point Initial Value Final Value Initial Value Final Value Density (ppg) 8.6 <9.2 <9.2* 9.6 Funnel Viscosity 250 250 150-200 55-65 (seconds) Yield Point 35-45 35-45 30-35 12-15 (eP) pH 9-9.5 9-9.5 9-9.5 9-9.5 API Filtrate 6 6 4-6 4-6 (ee / 30 min» Chlorides (mg/l) <600 <600 <600 <600 *9.6 ppg if hydrates are encountered Production Hole Mud Program (LSND) 95/8" Casin 7 Shoe to TD Initial Value Final Value Density (ppg) 9.6 9.6 Yield Point 22-28 10-15 (eP) pH 9-9.5 9-9.5 API Filtrate 4-6 4 (cc/30min» HTHP @ 1Srf (ee)) <12 <12 t/ Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033. Please see information on file with the Commission for diagrams and descriptions of the fluid system of Doyon Rig 141. 9. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) An application for a Permit to Drill must be accompanied by each of the following Item~ except for an Item already on flle with the commission and Identified in the application: (9) for an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 MC 25.033(f),· Not applicable: Application is not for an exploratory or stratigraphic test well. ORIGINAL 2P-419 PERMIT IT. doc Page 5 of 7 Printed: 13-Jan-04 · :e·· . ¡cation for Permit to Drill, Well 2P-419 Revision No.O Saved: 13-Jan-04 10. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application: (10) for an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 MC 25.061(a); Not applicable: Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already 017 file with the commission and identified in the application: (11) tor a well drilled from an offshore platform, mobile bottom-founded structure, jackcup rig or floating dnï/ing vessel, an analysis of seabed conditions as required by 20 MC 25.061(b); Not applicable: Application is not for an offshore well. 12. Evidence of Bonding Requirements of 20 AAC 25.005 (c)(12) An application for a Permit to Drill must be accompanied by each of the fa/lowing Items, except for an item already on file with the commission and identified in the application: (12) evidence showing that the requirements of 20 AAC 25.025 {Bonding}have been met; Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. 13. Proposed Drilling Program Requirements of 20 AAC 25.005 (c)(13) An application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file witll the commission and identified in the application: The proposed drilling program is listed below. Please refer also to Attachment 4, Well Schematics. 1. Move in / rig up Doyon Rig 141. Install 21-1/4" Annular with 16" diverter line and function test (conductor has already been installed and cemented). 2. Spud and directionally drill 12 V4" hole to casing point at 3292' MD / 2355' 1VD as per directional plan. Run MWD tools as required for directional monitoring and LWD tools as required for data acquisition. 3. Run and cement 95/8",40# L-80, STC casing to surface. Displace cement with mud. Perform top job if required. 4. Remove diverter system and install wellhead and test. Install and test 13 5/8" x 5,000 psi SOP's and test to 5000 psi (annular preventer to 3500 psi). Notify AOGCC 24 hrs before test. 5. PU 8 '12" bit and 6 V4" drilling assembly, with MWD and LWD (GR, resistivity & neutron density). RIH, clean out cement to top of float equipment. Pressure test casing to 3500 psi for 30 minutes and record results. 6. Drill out cement and 20' of new hole. Perform LOT or FIT to 18.0 ppg EMW, recording results. 7. Directionally drill to 7" x 4 V2" casing point at 10849 MD /5612' 1VD. 8. Run 7", 26# L-80, STC Mod x 4 V2", 12.6# L-80, 1ST Mod casing to TD. Pump cement and displace with water and mud. Note that the cross over and seal bore extension for the completion will be positioned 200' MD above the Cairn interval, if present, as this is an interval that may be produced later in the life of the field. 9. Make up completion string as required and RIH to depth. Locate seal bore extension, space out and land completion. Pressure test completion and production casing to 3500 psi for 30 minutes and record results. Shear RP shear valve in gas lift mandrel. 10. Install SPV, nipple down stack, nipple up and test tree to 5,000 psi. Pull SPV ORIGIN/\ 2P-419 PERMIT IT.doc Page 6 of 7 Printed: 13-Jan-04 · .'cation for Permit to Drill, Well 2P-419 Revision No.O Saved: 13-Jan-04 11. Freeze protect well with diesel by pumping into the annulus, taking returns from tubing and allowing to equalize. Carry out LOT and injection test on the outer annulus. Sweep the annulus with water and freeze protect. 12. Set BPV and move rig off. 13. Rig up wire line unit. Pull BPV. Set dummy valve in place of RP shear valve in gas lift mandrel. Perform MIT pressure tests of tubing and annulus (Tubing and annulus to 3500 psi). 14. Run cement bond log and perforate. Rig down wire line unit. 15. Freeze protect well and turn well over to production. 14. Discussion of Mud and Cuttings Disposal and Annular Disposal Requirements of 20 AAC 25.005 (c)(14) An application for a Permit to Drill mustc be accompanied by each of the following items; except for an item already on file with the commission and Identified in the application: (14) a general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator liJtends to request authorization under 20 MC 25.080 for an annular disposal operation Ii) the well.; Waste fluids generated during the drilling process will be disposed of either by pumping authorized fluids into a permitted annulus on 2P Pad, or by hauling the fluids to a KRU Class II disposal well. All cuttings generated will be disposed of either down a permitted annulus on 2P Pad, hauled to the Prudhoe Bay Grind and Inject Facility for temporary storage and eventual processing for injection down an approved disposal well, or stored, tested for hazardous substances, and used on the pad in accordance with a permit from the State of Alaska. At the end of drilling operations, an application may be submitted to permit 2P-419 for annular disposal of fluids occurring as a result of future drilling operations on 2P pad. 15. Attachments Attachment 1 Directional Plan (16 pages) Attachment 2 Drilling Hazards Summary (1 page) Attachment 3 Cement Loads and CemCADE Summary (2 page) Attachment 4 Well Schematics (1 page) ORIGINAL 2P-419 PERMIT IT.doc Page 7 of 7 Printed: 13-Jan-04 0 400 800 1200 0 1600 ......... -+- :::0 CD CD 2000 ...... - ......." GJ ..r: -+- 2400 a.. - CD :z 0 » 0 2800 Ü r ..... I- CD 3200 > CD ::¡ 3600 l- f- I V 4000 4400 4800 5200 5600 RKB Elevation: 252' KOP 2.00 4.00 6.00 DLS: 2.00 deg per 100 ft 8.00 Bld/Tm 3/100 14.45 1Ió4~6 Bld/Tm 4/100 2i8~~1 DLS: 4.00 deg per 100 ft 32.50 Base Permafrost 40.47 48.45 56.44 EOC Base West Sak 6000 o r-- I I ConocoPhillips Alaska, Inc. Structure : Drill Site 2P Field : Meltwater Well: 419 Location : North Slope, Alaska 195.68 AZIMUTH 7633' (TO TARGET) ***Plane of Proposal*** ~ 6397 Bld/Trn 3/100 9 5/8 CSG Þ . 63.02C80 62.3682.08 DLS: 3.00 deg per 100 ft 62.10 62.45 63.13 C50 64.12 End Bld/Tm C40 C37 TANGENT ANGLE 64.89 DEG 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800 7200 7600 8000 8400 ¥ ConocoPhillips Crected by bmíchcel Date plotted: 9-Jan-2004 Plot Reference is 2P-419 VerD5A Coordinates are In feet reference slot (1419. I""' ~'"'" "'.. ,. ~- "" '0- '" ..KIll HUGH" INTEQ . . 7 X 4 1/2 XO T4.2(Top Caim) T4.1 T3(Top Bermuda) Target Vertical Section (feet) - > Azimuth 195.68 with reference 0.00 N, 0.00 E from slot #419 Created by bmtchtJel Dote plotted: 9-Jan-2004 Plot Reference fs 2P-419 VtKH5A CoOf'dÎnales ore in feet reference slot 1419_ True VeJ'IÎcol Depths ore reference RKB (Doyon 141). Ira. .... INTEQ . . Structure: Drill Site 2P ConocoPhillips Alaska, Well: 419 Inc. Field : Meltwater Location: North Slope, Alaska - - ---2800 2400 2000 800 <- West (feet) 800 1600 1200 400 o 400 SURFACE LOCATION: 888' FNL, 2148' FWL SEC. 17, T8N, R7E 195.68 AZIMUTH 7633' (TO TARGET) ***Plone of ProposaJ*** 1: TRUE ~ ~ '1/ 0/ / TARGET LOCATION: 2581' FSL, 133' FWL SEC. 20, T8N, R7E TO LOCATION: 2014' FSL, 226' FEL SEC. 19, T8N, R7E ~ ConocoPhillips 1200 ..L~__l o 400 800 1200 1600 9 5/8 CS9 C80 2000 2400 2800 3200 (j') 0 !: 3600 - ::J'" ----. -- 4000 CD CD - "-" 4400 I V 4800 5200 5600 6000 6400 6800 7200 7600 8000 ORIGINAL o :::0 - G> - :z: » r- Created by Dote plotted: 9-Jan-2004 Plot Reference is 2P-419 Ver#5.A. Coordinates ore in feet reference 310t 1419. VertÎcol Depths (Ire reference RKB (Doyon II'. ..... INTEQ ---- ----- Point ----- KOP ¡Bld/Trn 3/100 IBld/Trn 4/100 Base Permafrost EOC Base West Sak 9 5/8 Csg IBld/Trn 3/100 IC80 IC50 lEnd Bld/Trn 'C40 C37 17 7 x 4 1/2 XO T4.2(Top Cairn) T4.1 n(Top Bermuda) TargS !T2(BaSe Bermuda) C35 TD, Csg PL ConocoPhillips Alaska, Inc. Structure: Drill SIte 2P Well : 419 L- Field: Meltwater Location : North Slope, Alaska PROF~LE COMMENT DATA MD ,. 250.00 750.00 1085.81 1399.19 2189.28 2372.38 3291.69 3394.34 3507.20 4726.80 . 4924.85· 5398.73 5811.16 8295.19 9462.11 9662.11 9768.16 10109.89 10659.02 10753.29 10849.02 v Inc 0.00 10.00 20.00 32.46 64.00 64.00 64.00 64.00 63.42 63.73 64.89 64.89 64.89 64.89 64.89 64.89 64.89 64.89 64.89 64.89 64.89 Dir 150.00 150.00 155.00 1 58.1 3 161.00 161.00 161.00 161.00 164.72 205.76 212.22 212.22 212.22 212.22 212.22 212.22 212.22 212.22 212.22 212.22 212.22 TVD North 250.00 0.00 747.47 -37.69 1071.43 -115.19 1352.00 -242.32 1871.73 -788.73 1952.00 -944.34 2355.00 -1725.59 2400.00 -1812.83 2450.00 -1909.50 3012.00 -2964.14 3097.93 -3120.10 3299.00 -3483.12 3474.00 ~3799.06 4528.00 -5701.93 5023.14 -6595.84 5108.00 -6749.05 5153.00 -6830.29 5298.00 -7092.07 5531.00 -7512.73 5571.00 -7584.94 5611.62 ,,/ -7658.28 ~ ConocoPhillips ---- East 0.00 21.76 60.71 114.91 314.59 368.17 637.17 667.21 697.03 599.80 513.32 284.51 85.37 -1114.02 -1677.46 -1774.03 -1825.24 -1990.24 -2255.38 -2300.90 -2347.12 V. Sect 0.00 30.41 94.50 202.26 674.40 809.74 1489.25 1565.13 1650.15 2691.83 2865.36 3276.69 3634.69 5790.85 6803.76 6977.36 7069.41 7366.04 7842.69 7924.52 8007.61 . Deg/l00 0.00 2.00 3.00 4.00 4.00 0.00 0.00 0.00 3.00 ~:~~ . 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 , Inc. ""/" ConoçoPhillips DOte p!ol,t¢<:i; .$.,..-Jqo-2oo4 Field: Location Slope, Ala$ka TRU E NO @D@J) ? 800 40 310 50 300 290 70 280 80 270 90 260 100 250 110 240 120 230 130 220 140 210 1 :30 200 160 190 180 170 Normal Plane Travelling Cylinder - All depths shown are Measured depths on nee Well Crected by brnichoe! Date plotted ; Plot RefGrence Í$ CoordiMtes are in feat reference slot I4HL Vert;col 120 80 RK6 (Doyon 40 ConocoPhillips Alaska, Inc. "",,/ ConocoPhillips Structure: Drill Site 2P Well : 4 i 9 Field: Meltwater location : North Slape, East (feet) -> o 120 480 160 200 240 280 320 360 400 440 40 80 80 01 900 / @300 ~,,700 ...900 40 100 '0 J300 0 406 40 100 80 120 160 1500 200 " " (f) 240 0 C 700 -- ::::r 280 ,,--..., -. CD CD -- 320 ~ " " I V \ 360 \ \ 1900 \ 400 \ ~ \ \ 440 1700 \ \ \ 1900 \ 480 \ \ \ 520 , 1700 \ \ 560 \ \ \ 600 1901S¡ \ \ 640 \ 680 70& \ \ 90cf \ \ \ \ \, 1100 \ \ \ \ \ \ \, 1300 \ \ 150p \ \ \ 900 1100 1100 1300 1500 c Cr~ted by bmlchat:! Dot¢ pl9tted: 9-Jq!lc-';?_OO4 Plot i, COQrdinates føet (a!'ßran~ $!pt #419_ 141). 200 100 o 100 Structure: Field: Meltwater Location East (feet) > 200 400 500 300 2300 2900 2700 600 2300 ~""".~ ConocoPhillips 1100 1200 1300 600 700 800 900 1000 2500 1100 1200 1300 1400 tf) 0 ¡: 1500 - :J'" 1600 1700 ¡ V 1800 1900 2000 2100 2200 2300 4100 2400 4300 2500 700 800 900 \ \ \ \ \ \ \ \ \ \ \ ~ 2100 \ \ \ \ \ \ \ \ \ \ \ \, 2300 \ \ \ \ \ \ \ \ \ \ \ 1 2500 \ \ \ \ \ \ I I I I f 2700 I I êJ Created by bmichoe! DQte plotted: 9~JCln-2004 P!ot~tdørai1ç>;! [$ ,ZP-419 Vw!l5A RKß (Doyon c <- (feet) 3600 3200 2800 2400 ~ ~ 4500 3000 5000 5500 / 4000 / / (Ø / / / / / / /4500 / / / / / / /5000 / / / ø / /5500 / 3500 1 / 4000/ / / / / 4500 5000 5500 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 I V 6400 6800 5500 7200 7600 8000 8400 8800 9200 9600 . . ConocoPhillips Alaska, Inc. Drill Site 2P 419 slot #419 Meltwater North Slope, Alaska PRO P 0 S ALL I S TIN G by Baker Hughes INTEQ Your ref Our ref License 2P-419 Ver#5.A prop5597 Date printed Date created Last revised 9-Jan-2004 7-Jan-2004 9-Jan-2004 Field is centred on 441964.235,5869891.466,999.00000,N Structure is centred on 441964.235,5869891.466,999.00000,N Slot location is n70 3 9.792,w150 2~ 50.215 Slot Grid coordinates are N 5868988.020,vE 444108.030 ~ Slot local coordinates are 887.17 S 2150.82 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North ORIGINAL . ConocoPhillips Alaska, Inc. Drill 8ite 2P,419 Meltwater,North 81ope, Alaska Measured Inclin. Azimuth True Vert Depth Degrees Degrees Depth 0.00 100.00 200.00 250.00 350.00 450.00 550.00 650.00 750.00 800.00 4.00 6.00 8.00 10.00 11.48 900.00 1000.00 1085.81 1100.00 1200.00 14.45 17.44 20.00 20.56 24.53 1300.00 1399.19 28.51 32.46 1400.00 1500.00 1600.00 32.50 36.48 40.47 1700.00 1800.00 1900.00 2000.00 2100.00 44.46 48.45 52.45 56.44 60.43 2189.28 2372.38 2500.00 3000.00 3291.69 64.00 64.00 64.00 64.00 64.00 3394.34 3400.00 3500.00 3507.20 3600.00 64.00 63.97 63.46 63.42 63.02 3700.00 3800.00 3900.00 4000.00 4100.00 62.66 62.38 62.19 62.08 62.04 4200.00 4300.00 4400.00 4500.00 4600.00 62.10 62.23 62.45 62.75 63.13 4700.00 4726.80 4800.00 4900.00 4924.85 63.59 63.73 64.12 64.73 64.89 0.00 0.00 0.00 0.00 2.00 0.00 150.00 150.00 150.00 150.00 0.00 100.00 200.00 250.00 349.98 449.84 549.45 648.70 747.47 796.59 894.03 990.17 1071.43 1084.74 1177.08 1266.54 1352.00 1352.68 1435.09 1513.36 1587.11 1655.99 1719.65 1777.79 1830.13 1871.73 1952.00 2007.95 2227.13 2355.00 2400.00 2402.48 2446.78 2450.00 2491. 82 2537.47 2583.62 2630.14 2676.90 2723.76 2770.61 2817.31 2863.74 2909.76 2955.26 3000.11 3012.00 3044.18 3087.35 3097.93 R E C TAN G U L A R COO R DIN ATE 8 0.00 N 0.00 N 0.00 N 0.00 N 1. 51 8 6.04 8 13.59 8 24.14 8 37.69 8 45.82 8 65.68 8 90.30 8 115.19 8 119.65 8 154.64 8 195.73 8 242.32 8 242.72 8 295.37 8 353.43 8 416.61 8 484.61 8 557.10 8 633.73 8 714.11 8 788.73 8 944.34 8 1052.79 8 1477.718 1725.59 8 1812.83 8 1817.64 8 1903.29 8 1909.50 8 1989.96 8 2077.42 8 2165.43 8 2253.74 8 2342.13 8 2430.33 8 2518.12 8 2605.24 8 2691.47 8 2776.57 8 2860.29 8 2942.42 8 2964.14 8 3022.73 8 3101. 00 8 3120.10 8 0.00 E 0.00 E 0.00 E 0.00 E 0.87 E 3.49 E 7.85 E 13.94 E 21. 76 E 26.32 E 36.76 E 48.92 E 60.71 E 62.78 E 78.43 E 95.89 E 114.91 E 115.07 E 135.88 E 158.21 E 181. 96 E 207.02 E 233.25 E 260.54 E 288.74 E 314.59 E 368.17 E 405.51 E 551. 82 E 637.17 E 667.21 E 668.86 E 695.32 E 697.03 E 716.71 E 732.95 E 744.01 E 749.86 E 750.48 E 745.87 E 736.04 E 721.02 E 700.85 E 675.59 E 645.30 E 610.07 E 599.80 E 569.99 E 525.18 E 513.32 E Dogleg Deg/l00ft 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00 3.00 . PROP08AL LI8TING Page 1 Your ref 2P-419 Ver#5.A Last revised 9-Jan-2004 Vert Sect 0.00 0.00 0.00 0.00 2.00 0.00 0.00 0.00 0.00 KOP 1.22 150.00 150.00 150.00 150.00 151.28 153.07 154.26 155.00 155.22 156.48 157.41 158.13 158.13 158.71 159.19 159.59 159.94 160.26 160.53 160.79 161. 00 161. 00 161. 00 161. 00 161.00 161. 00 161.19 164.48 164.72 167.81 171 . 15 174.52 177.90 181. 29 184.69 188.09 191.47 194.85 198.21 201. 56 204.87 205.76 208.16 211. 42 212.22 2.00 2.00 2.00 2.00 3.00 4.88 10.97 19.48 30.41 Bld/Trn 3/100 37.00 3.00 3.00 3.00 4.00 4.00 53.30 73.73 94.50 Bld/Trn 4/100 98.24 127.70 4.00 4.00 162.55 202.26 Base Permafrost 4.00 4.00 4.00 202.60 247.67 297.53 4.00 4.00 4.00 4.00 4.00 351. 95 410.66 473.36 539.76 609.54 4.00 0.00 0.00 0.00 0.00 674.40 EOC 809.74 Base West 8ak 904.07 1273.65 1489.25 9 5/8 Csg 0.00 3.00 3.00 3.00 3.00 1565.13 Bld/Trn 3/100 1569.32 1644.63 1650.15 C80 1722.30 3.00 3.00 3.00 3.00 3.00 1802.12 1883.86 1967.31 2052.24 2138.41 2225.59 2313.53 2402.00 2490.76 2579.56 2668.15 2691. 83 C50 2756.30 2843.76 2865.36 End Bld/Trn All data is in feet unless otherwise stated. Coordinates from slot #419 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level). Bottom hole distance is 8009.88 on azimuth 197.04 degrees from wellhead. Total Dogleg for wellpath is 110.13 degrees. Vertical section is from wellhead on azimuth 195.68 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ ORIGINAL . . ConocoPhillips Alaska, Inc. PROPOSAL LISTING Page 2 Drill Site 2P,419 Your ref 2P-419 Ver#5.A Meltwater,North Slope, Alaska Last revised 9-Jan-2004 Measured Inclin. Azimuth True Vert R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOft Sect 5000.00 64.89 212.22 3129.81 3177.67 S 477.03 E 0.00 2930.59 5398.73 64.89 212.22 3299.00 3483.12 S 284.51 E 0.00 3276.69 C40 5500.00 64.89 212.22 3341. 97 3560.69 S 235.61 E 0.00 3364.60 5811.16 64.89 212.22 3474.00 3799.06 S 85.37 E 0.00 3634.69 C37 6000.00 64.89 212.22 3554.13 3943.71 S 5.81 W 0.00 3798.60 6500.00 64.89 212.22 3766.28 4326.74 S 247.23 W 0.00 4232.61 7000.00 64.89 212.22 3978.44 4709.76 S 488.65 W 0.00 4666.62 7500.00 64.89 212.22 4190.59 5092.78 S 730.07 W 0.00 5100.62 8000.00 64.89 212.22 4402.75 5475.80 S 971.49 W 0.00 5534.63 8295.19 64.89 212.22 4528.00 5701.93 S 1114.02 W 0.00 5790.85 T7 8500.00 64.89 212.22 4614.90 5858.82 S 1212.91 W 0.00 5968.63 9000.00 64.89 212.22 4827.06 6241.85 S 1454.34 W 0.00 6402.64 9462.11 64.89 212.22 5023.14 6595.84 S 1677.46 W 0.00 6803.76 7 x 4 1/2 XO 9500.00 64.89 212.22 5039.22 6624.87 S 1695.76 W 0.00 6836.65 9662.11 64.89 212.22 5108.00 6749.05 S 1774.03 W 0.00 6977.36 T4.2(Top Cairn) 9768.16 64.89 212.22 5153.00 6830.29 S 1825.24 W 0.00 7069.41 T4.1 10000.00 64.89 212.22 5251.37 7007.89 S 1937.18 W 0.00 7270.65 10109.89 64.89 212.22 5298.00 7092.07 S 1990.24 W 0.00 7366.04 2P-443 Top Berm Tgt 22 Jul 03 10500.00 64.89 212.22 5463.53 7390.91 S 2178.60 W 0.00 7704.66 10659.02 64.89 212.22 5531. 00 7512.73 S 2255.38 W 0.00 7842.69 T2(Base Bermuda) 10753.29 64.89 212.22 5571.00 7584.94 S 2300.90 W 0.00 7924.52 C35 10849.02 64.89 212.22 5611.62 .- 7658.28 S 2347.12 W 0.00 8007.61 TD, Csg Pt. All data is in feet unless otherwise stated. Coordinates from slot #419 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level). Bottom hole distance is 8009.88 on azimuth 197.04 degrees from wellhead. Total Dogleg for wellpath is 110.13 degrees. Vertical section is from wellhead on azimuth 195.68 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ ORIGINAL . . ConocoPhillips Alaska, Inc. Drill 8ite 2P,4l9 Meltwater,North 8lope, Alaska PROP08AL LI8TING Page 3 Your ref 2P-419 Ver*5.A Last revised: 9-Jan-2004 Comments in wellpath -------------------- -------------------- MD TVD Rectangular Coords. Comment ----------------------------------------------------------------------------------------------------------- 250.00 250.00 0.00 N 0.00 E KOP 750.00 747.47 37.69 8 21.76 E Bld/Trn 3/100 1085.81 1071.43 115.19 8 60.71 E Bld/Trn 4/100 1399.19 1352.00 242.32 8 114.91 E Base Permafrost 2189.28 1871.73 788.73 8 314.59 E EOC 2372.38 1952.00 944.34 8 368.17 E Base West 8ak 3291.69 2355.00 1725.59 8 637.17 E 9 5/8 Csg 3394.34 2400.00 1812.83 8 667.21 E Bld/Trn 3/100 3507.20 2450.00 1909.50 8 697 . 03 E C80 4726.80 3012.00 2964.14 8 599.80 E C50 4924.85 3097.93 3120.10 8 513 .32 E End Bld/Trn 5398.73 3299.00 3483.12 8 284.51 E C40 5811.16 3474.00 3799.06 8 85.37 E C37 8295.19 4528.00 5701.93 8 1114.02 W T7 9462.11 5023.14 6595.84 8 1677.46 W 7 x 4 1/2 XO 9662.11 5108.00 6749.05 8 1774.03 W T4.2(Top Cairn) 9768.16 5153.00 6830.29 8 1825.24 W T4.1 10109.89 5298.00 7092.07 8 1990.24 W 2P-443 Top Berm Tgt 22 Jul 03 10659.02 5531. 00 7512.73 8 2255.38 W T2(Base Bermuda) 10753.29 5571. 00 7584.94 8 2300.90 W C35 10849.02 5611. 62 7658.28 8 2347.12 W TD, Csg Pt. Casing positions in string 'A' ------------------------------ ------------------------------ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing ----------------------------------------------------------------------------------------------------------- 0.00 0.00 0.00 0.00 O.OON O.OON O.OOE 3394.34 2400.00 O.OOE 10849.00 5611.61 1812.838 7658.268 667.21E 9 5/8" C8G 2347.11W 4 1/2" Liner Targets associated with this wellpath ------------------------------------- ------------------------------------- Target name Geographic Location T.V.D. Rectangular Coordinates Revised ----------------------------------------------------------------------------------------------------------- 2P-443 Top Berm Tgt 442064.000,5861912.000,999.00 5298.00 7092.078 1990.24W 22-Feb-2001 ORIG1N!4 . . ConocoPhillips Alaska, Inc. Drill Site 2P 419 slot #419 Meltwater North Slope, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License 2P-4l9 Ver#5.A prop5597 Date printed Date created Last revised l2-Jan-2004 7-Jan-2004 9-Jan-2004 Field is centred on 441964.235,5869891. 466,999.00000, N Structure is centred on 44l964.235,5869891.466,999.00000,N Slot location is n70 3 9.792,w150 26 50.215 Slot Grid coordinates are N 5868988.020, E 444108.030 Slot local coordinates are 887.17 S 2150.82 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North ORIGf~L~ . . ConocoPhillips Alaska, Inc. PROP05AL LI5TING Page 1 Drill Site 2P,419 Your ref 2P-419 Ved5.A Meltwater ,North Slope, Alaska Last revised , 9-Jan-2004 Measured Inclin Azimuth True Vert R E C TANGULA R G RID COO R D 5 G E o G RAP H I C Depth Degrees Degrees Depth C 0 0 R DIN ATE 5 Easting Northing C 0 ORDINAT E 5 0.00 0.00 0.00 0.00 O.OON O.OOE 444108.03 5868988.02 n70 09.79 w150 26 50.21 100.00 0.00 150.00 100.00 O.OON O.OOE 444108.03 5868988.02 n70 09.79 w150 26 50.21 200.00 0.00 150.00 200.00 O.OON O.OOE 444108.03 5868988.02 n70 09.79 w150 26 50.21 250.00 0.00 150.00 250.00 O.OON O.OOE 444108.03 5868988.02 n70 09.79 w150 26 50.21 350.00 2.00 150.00 349.98 1. 515 0.87E 444108.89 5868986.50 n70 09.78 w150 26 50.19 450.00 4.00 150.00 449.84 6.045 3.49E 444111.47 5868981.95 n70 3 09.73 w150 26 50.11 550.00 6.00 150.00 549.45 13 .595 7.85E 444115.77 5868974.37 n70 3 09.66 w150 26 49.99 650.00 8.00 150.00 648.70 24.145 13.94E 444121.78 5868963.77 n70 3 09.55 w150 26 49.81 750.00 10.00 150.00 747.47 37.695 21.76E 444129.50 5868950.17 n70 3 09.42 w150 26 49.59 800.00 11.48 151. 28 796.59 45.825 26.32E 444134.00 5868942.01 n70 3 09.34 w150 26 49.46 900.00 14.45 153.07 894.03 65.685 36.76E 444144.28 5868922.07 n70 09.15 w150 26 49.16 1000.00 17.44 154.26 990.17 90.305 48.92E 444156.26 5868897.35 n70 08.90 w150 26 48.81 1085.81 20.00 155.00 1071.43 115.195 60.71E 444167.85 5868872 .38 n70 08.66 w150 26 48.47 1100.00 20.56 155.22 1084.74 119.655 62.78E 444169.89 5868867.91 n70 08.62 w150 26 48.41 1200.00 24.53 156 .48 1177 .08 154.645 78.43E 444185.27 5868832.80 n70 08.27 w150 26 47.96 1300.00 28.51 157.41 1266.54 195.735 95.89E 444202.42 5868791.58 n70 07.87 w150 26 47.45 1399.19 32.46 158 . 13 1352.00 242.325 114.91E 444221.08 5868744.86 n70 07.41 w150 26 46.91 1400.00 32.50 158.13 1352.68 242.725 115.07E 444221.23 5868744.46 n70 07.40 w150 26 46.90 1500.00 36.48 158.71 1435.09 295.375 135.88E 444241.64 5868691.65 n70 06.89 w150 26 46.30 1600.00 40.47 159.19 1513.36 353.435 158.21E 444263.53 5868633.43 n70 06.32 w150 26 45.66 1700.00 44.46 159.59 1587.11 416.615 181.96E 444286.80 5868570.07 n70 05.69 w150 26 44.98 1800.00 48.45 159.94 1655.99 484.615 207.02E 444311.33 5868501.89 n70 05.03 w150 26 44.26 1900.00 52.45 160.26 1719.65 557.105 233.25E 444337.01 5868429.21 n70 04.31 w150 26 43.50 2000.00 56.44 160.53 1777.79 633.735 260.54E 444363.71 5868352.39 n70 03.56 w150 26 42.72 2100.00 60.43 160.79 1830.13 714.115 288.74E 444391.29 5868271.80 n70 02.77 w150 26 41. 90 2189.28 64.00 161.00 1871.73 788.735 314.59E 444416.57 5868196.99 n70 02.03 w150 26 41.16 2372.38 64.00 161.00 1952.00 944.345 368.17E 444468.95 5868041.00 n70 00.50 w150 26 39.62 2500.00 64.00 161.00 2007.95 1052.795 405.51E 444505.47 5867932.27 n70 2 59.44 w150 26 38.54 3000.00 64.00 161. 00 2227.13 1477.715 551. 82E 444648.52 5867506.29 n70 2 55.26 w150 26 34.33 3291. 69 64.00 161.00 2355.00 1725.595 637.17E 444731. 98 5867257.79 n70 2 52.82 w150 26 31. 88 3394.34 64.00 161.00 2400.00 1812.835 667.21E 444761.35 5867170.33 n70 2 51. 96 w1S0 26 31. 01 3400.00 63.97 161.19 2402.48 1817.645 668.86E 444762.96 5867165.51 n70 2 51. 91 w150 26 30.97 3500.00 63.46 164.48 2446.78 1903.295 695.32E 444788.76 5867079.67 n70 2 51. 07 w150 26 30.21 3507.20 63.42 164.72 2450.00 1909.505 697.03E 444790.43 5867073.45 n70 2 51.01 w150 26 30.16 3600.00 63.02 167.81 2491. 82 1989.965 716.71E 444809.48 5866992.85 n70 2 50.22 w150 26 29.59 3700.00 62.66 171.15 2537.47 2077 . 425 732.95E 444825.06 5866905.28 n70 2 49.36 w150 26 29.12 3800.00 62.38 174.52 2583.62 2165.435 744.01E 444835.45 5866817.19 n70 2 48.49 w150 26 28.81 3900.00 62.19 177.90 2630.14 2253.745 749.86E 444840.62 5866728.84 n70 2 47.62 w150 26 28.64 4000.00 62.08 181. 29 2676.90 2342.135 750.48E 444840.57 5866640.47 n70 2 46.75 w150 26 28.62 4100.00 62.04 184.69 2723.76 2430.335 745.87E 444835.29 5866552.31 n70 2 45.89 w150 26 28.76 4200.00 62.10 188.09 2770.61 2518.125 736.04E 444824.79 5866464.61 n70 2 45.02 w150 26 29.04 4300.00 62.23 191. 47 2817.31 2605.245 721. 02E 444809.11 5866377.61 n70 2 44.17 w150 26 29.47 4400.00 62.45 194.85 2863.74 2691.475 700.85E 444788.29 5866291. 54 n70 2 43.32 w150 26 30.05 4500.00 62.75 198.21 2909.76 2776.575 675.59E 444762.38 5866206.65 n70 2 42.48 w150 26 30.78 4600.00 63.13 201. 56 2955.26 2860.295 645.30E 444731.45 5866123.17 n70 2 41. 66 w150 26 31. 66 4700.00 63.59 204.87 3000.11 2942.425 610.07E 444695.60 5866041.32 n70 2 40.85 w150 26 32.67 4726.80 63.73 205.76 3012.00 2964.145 599.80E 444685.16 5866019.68 n70 2 40.64 w150 26 32.97 4800.00 64.12 208.16 3044.18 3022.735 569.99E 444654.91 5865961.32 n70 2 40.06 w150 26 33.83 4900.00 64.73 211. 42 3087.35 3101. 005 525.18E 444609.51 5865883.41 n70 2 39.29 w150 26 35.12 4924.85 64.89 212.22 3097.93 3120.105 513 .32E 444597 . 51 5865864.40 n70 2 39.10 w150 26 35.46 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #419 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level). Bottom hole distance is 8009.88 on azimuth 197.04 degrees from wellhead. Total Dogleg for wellpath is 110.13 degrees. Vertical section is from wellhead on azimuth 195.68 degrees. ORIGINAL . . Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ ConocoPhillips Alaska, Inc. PROPOSAL LI5TING Page 2 Drill Site 2P,419 Your ref 2P-419 Ver#5.A Meltwater,North Slope, Alaska Last revised : 9-Jan-2004 Measured Inclin Azimuth True Vert R E C TANGULA R G RID COO R D 5 G E OG RAPHIC Depth Degrees Degrees Depth C 0 0 RDINATE 5 Eas t ing Northing C 0 o R DIN ATE 5 5000.00 64.89 212.22 3129.81 3177.675 477.03E 444560.79 5865807.11 n70 2 38.54 w150 26 36.50 5398.73 64.89 212.22 3299.00 3483.125 284.51E 444365.96 5865503.17 n70 2 35.53 w150 26 42.05 5500.00 64.89 212.22 3341. 97 3560.695 235.61E 444316.48 5865425.98 n70 2 34.77 w150 26 43.46 5811.16 64.89 212.22 3474.00 3799.065 85.37E 444164.44 5865188.79 n70 2 32.43 w150 26 47.79 6000.00 64.89 212.22 3554.13 3943.715 5.81W 444072 .17 5865044.84 n70 2 31. 00 w150 26 50.41 6500.00 64.89 212.22 3766.28 4326.745 247.23W 443827.86 5864663.71 n70 2 27.24 w150 26 57.37 7000.00 64.89 212.22 3978 .44 4709.765 488.65W 443583.55 5864282.57 n70 2 23.47 w150 27 04.32 7500.00 64.89 212.22 4190.59 5092.785 730.07W 443339.24 5863901.44 n70 2 19.71 w150 27 11.27 8000.00 64.89 212.22 4402.75 5475.805 971.49W 443094.93 5863520.31 n70 2 15.94 w150 27 18.22 8295.19 64.89 212 .22 4528.00 5701. 935 1114.02W 442950.70 5863295.29 n70 2 13.71 w150 27 22.33 8500.00 64.89 212.22 4614.90 5858.825 1212.91W 442850.62 5863139.17 n70 2 12.17 w150 27 25.18 9000.00 64.89 212 .22 4827.06 6241.855 1454.34W 442606.31 5862758.04 n70 2 08.40 w150 27 32.13 9462.11 64.89 212.22 5023.14 6595.845 1677.46W 442380.52 5862405.78 n70 2 04.92 w150 27 38.55 9500.00 64.89 212.22 5039.22 6624.875 1695.76W 442362.00 5862376.90 n70 2 04.64 w150 27 39.07 9662.11 64.89 212.22 5108.00 6749.055 1774.03W 442282.80 5862253.33 n70 2 03.42 w150 27 41.33 9768.16 64.89 212.22 5153.00 6830.295 1825.24W 442230.98 5862172.49 n70 2 02.62 w150 27 42.80 10000.00 64.89 212.22 5251.37 7007.895 1937.18W 442117.70 5861995.77 n70 2 00.87 w150 27 46.02 10109.89 64.89 212.22 5298.00 7092.075 1990.24W 442064.00 5861912.00 n70 2 00.04 w150 27 47.55 10500.00 64.89 212.22 5463.53 7390.915 2178.60W 441873.39 5861614.63 n70 1 57.10 w150 27 52.97 10659.02 64.89 212.22 5531. 00 7512.735 2255.38W 441795.69 5861493.42 n70 1 55.91 w150 27 55.18 10753.29 64.89 212.22 5571.00 7584.945 2300.90W 441749.62 5861421.56 n70 1 55.20 w150 27 56.49 10849.02 64.89 212.22 5611. 62 7658.285 2347.12W 441702.85 5861348.59 n70 1 54.47 w150 27 57.82 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #419 and TVD from RKB (Doyon 141) (252.00 Ft above mean sea level). Bottom hole distance is 8009.88 on azimuth 197.04 degrees from wellhead. Total Dogleg for wellpath is 110.13 degrees. ORtGlt\1 · . Vertical section is from wellhead on azimuth 195.68 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ ConocoPhillips Alaska, Inc. Drill 5ite 2P.419 Meltwater,North Slope, Alaska PROP05AL LI5TING Page 3 Your ref 2P-419 Ver#5.A Last revised: 9-Jan-2004 Comments in wellpath -------------------- -------------------- MD TVD Rectangular Coords. Comment - - - -- - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - -- 250.00 250.00 O.OON O.OOE KOP 750.00 747.47 37.695 21. 76E Bld/Trn 3/100 1085.81 1071.43 115.195 60.71E Bld/Trn 4/100 1399.19 1352.00 242.325 114.91E Base Permafros t 2189.28 1871. 73 788.735 314.59E EOC 2372 .38 1952.00 944.345 368.l7E Base West Sak 3291.69 2355.00 1725.595 637.17E 9 5/8 Csg 3394.34 2400.00 1812.835 667.21E Bld/Trn 3/100 3507.20 2450.00 1909.505 697 .03E C80 4726.80 3012.00 2964.145 599.80E C50 4924.85 3097.93 3120.105 513.32E End Bld/Trn 5398.73 3299.00 3483.125 284.51E C40 5811.16 3474.00 3799.065 85.37E C37 8295.19 4528.00 5701. 935 1114.02W T7 9462.11 5023.14 6595.845 1677.46W 7 x 4 1/2 xo 9662.11 5108.00 6749.055 1774.03W T4.2 (Top Cairn) 9768.16 5153.00 6830.295 1825.24W T4.1 10109.89 5298.00 7092.075 1990.24W 2P-443 Top Berm Tgt 22 Jul 03 10659.02 5531.00 7512.735 2255.38W T2 (Base Bermuda) 10753.29 5571. 00 7584.945 2300.90W C35 10849.02 5611.62 7658.285 2347.12W TD, Csg Pt. Casing positions in string 'A' ------------------------------ ------------------------------ Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing - - - - - - - - - - - - - - - - -- - - - - - - - --- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - -- - - - - - -- 0.00 0.00 0.00 0.00 O.OON O.OON O.OOE 3394.34 2400.00 O.OOE 10849.00 5611.61 1812.835 7658.265 667.21E 9 5/8" C5G 2347.11W 4 1/2" Liner Targets associated with this wellpath ------------------------------------- ------------------------------------- Target name Geographic Location T.V.D. Rectangular Coordinates Revised - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - -- - - - - - - - - - - - - -- - -- - - - - - - - - - - -- ----- 2P-443 Top Berm Tgt 442064.000.5861912.000,999.00 5298.00 7092.075 1990.24W 22-Feb-2001 ORIGINAL · . Baker Hughes Incorporated Anticollision Report NO GLOBAL SCAN: Using user defined selection & scan criteria Interpolation Method: MD Interval: 25.00 ft Depth Range: 0.00 to 10849.02 ft Maximum Radius: 5280.00 ft Reference: Error Model: Scan Method: Error Surface: Plan 2P-419 Ver#5a & NOT PLANNED OGR ISCWSA Ellipse Trav Cylinder North EHipse Plan: 2P-419 Ver#5a Date Composed: Version: Tied-to: 1/6/2004 6 From Surface Principal: Yes 2P Pad 406 2P-406 Vers#2.A V2 Pia 607.96 600.00 259.55 10.70 248.85 Pass: Major Risk 2P Pad 414 2P-414 Vers#3a V1 Plan 601.52 600.00 97.54 11.12 86.42 Pass: Major Risk 2P Pad 415 2P-415 VO 300.38 300.00 80.26 4.77 75.50 Pass: Major Risk 2P Pad 415 2P-415A VO 300.38 300.00 80.26 4.77 75.50 Pass: Major Risk 2P Pad 416 2P-416 Version#O.A VO 650.88 650.00 60.12 11.55 48.58 Pass: Major Risk 2P Pad 417 2P-417 VO 524.60 525.00 44.06 8.83 35.24 Pass: Major Risk 2P Pad 420 2P-420 VO 349.70 350.00 20.04 5.52 14.53 Pass: Major Risk 2P Pad 422 2P-422 V7 1215.23 1225.00 59.52 28.34 31.18 Pass: Major Risk 2P Pad 422 422A VO 1215.23 1225.00 59.52 28.34 31.18 Pass: Major Risk 2P Pad 424 2P-424 V5 1664.45 1675.00 82.13 50.83 31.30 Pass: Major Risk 2P Pad 427 2P-427 VO 4782.67 4800.00 206.94 165.04 41.90 Pass: Major Risk 2P Pad 429 2P-429 VO 592.83 600.00 201.71 10.47 191.24 Pass: Major Risk 2P Pad 431 2P-431 V1 6583.08 6150.00 334.54 200.28 134.27 Pass: Major Risk 2P Pad 432 2P-432 V12 396.09 400.00 261.12 6.85 254.27 Pass: Major Risk 2P Pad 434 2P-434 V4 322.77 325.00 301 .82 5.29 296.54 Pass: Major Risk 2P Pad 438 2P-438 VO 322.19 325.00 380.80 5.37 375.43 Pass: Major Risk 2P Pad 441 2P-441 VO 369.62 375.00 440.87 6.06 434.80 Pass: Major Risk 2P Pad 445 2P-445 Vers#4 VO Plan: 392.46 400.00 521.16 6.83 514.33 Pass: Major Risk 2P Pad 447 2P-447 V6 273.67 275.00 561.04 4.60 556.44 Pass: Major Risk 2P Pad 448 2P-448 V2 320.85 325.00 581.32 5.36 575.96 Pass: Major Risk 2P Pad 448 2P-448A VO 320.85 325.00 581.32 5.36 575.96 Pass: Major Risk 2P Pad 448 2P-448PB1 VO 320.85 325.00 581.32 5.36 575.96 Pass: Major Risk 2P Pad 449 2P-449 Vers#6.b V1 Pia 320.75 325.00 600.38 5.60 594.78 Pass: Major Risk 2P Pad 451 2P-451 VO 296.99 300.00 640.20 4.87 635.33 Pass: Major Risk Meltwater North#1 MWN#1 MWN#1 VO 8783.52 4775.00 1242.19 259.42 982.77 Pass: Major Risk Meltwater South #1 MWS#1 MWS#1 VO Out of range MWN#2 MWN#2 MWN#2 VO 3700.00 3625.00 2922.15 138.15 2783.99 Pass: Major Risk MWN#2 MWN#2 MWN#2A VO 3600.00 4200.00 2930.36 146.46 2783.90 Pass: Major Risk ORIG'~J . . MEL TW A TER - DRILLING HAZARDS SUMMARY 12 l¡4" Open Hole & 9 5/8" Surface Casin2 Interval Event Risk level Mitigation Strategy I Contingency Broach of conductor Low Monitor cellar continuously during interval Gas Hydrates Low If observed - control drill, reduce pump rates, reduce drilling fluid temperatures, additions of Lecithin Running sands & gravel Moderate Maintain planned mud parameters, Increase mud weight/viscosity, Use weighted sweeps, monitor fill on connections Drill surface hole into shallow Low Do not exceed the surface hole TD as detailed pressured interval - C-80 in the individual well plans, ensure that all charged stands (in the derrick or in the hole) are accounted for at all times Hole swabbing/Tight hole on Moderate Circulate hole clean prior to trip, proper hole trips filling (use of trip sheets), pumping out of hole as needed Stuck surface casing Low Clean the hole before running casing, pump high density high viscosity sweeps, wiper trip Stuck pipe Low Keep hole clean, use high density high viscosity sweeps, keep pipe moving/rotating with pumps on whenever possible Lost circulation Low Keep hole clean. If losses occur - reduce pump rates and mud rheoloav, use LCM 8 Vi' Open Hole & 5 Iii' x 3 Iii' Production Casin2 Interval Event Drill through a shallow pressured interval: C-80 to C-37 Insufficient or undetermined LOT Risk level Moderate Moderate High ECD / Tight hole on trips/ Swabbing Moderate Differential sticking Moderate Barite sa Lost circulation Low High Miti ation Strate I Contin enc Carry out well control drills. Kill fluid stored on location, contingency 7" casing string on location, hei htened awareness Importance of LOT communicated to all parties, all parties familiar with LOT procedure. Test will be carried out until leak off is observed or to an FIT of 18 MW e uivalent Condition mud & clean hole prior to trips. Monitor ECDs with PWD tool while drilling across reservoir interval. Hole cleaning best practices. Backream out on trips as a last resort, proper hole filling (use of trip sheets Keep hole clean, periodic wiper trips, keep pipe movin /rotatin with um s on whenever ossible Good drillin ractices as documented in well Ian Pretreat mud before drilling reservoir section, keep hole clean - use PWD to monitor hole cleaning. If losses occur - reduce pump rates and mud rheolo , use LCM ORIG!~JA, Meltwater Drilling Hazards Summary Prepared by Philip Hayden 1/12/2004 Rig: Doyon 141 Location: Kuparuk (Meltwater) Client: ConocoPhillips Alaska, Inc. Revision Date: 1/12/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6266 email: martin13@slb.com < TOC at Surface Previous Csg. < 16",62.6#, H-40 grade Welded Connection at 108 ft. MD < Sase of Permafrost at 1,399 ft. MD (1,352 ft. TVD) < Top ofTail at 1,892 ft. MD < 95/8", 40.0#, L-80 grade STC, AS Modified in 121/4" OH TO at 3,292 ft. MD (2,355 ft. TVD) Mark of Schlumberger SchluIDb8PgOP Preliminary Job Design based on limited input data. For estimate purposes oniy. Volume Calculations and Cement Systems (Volumes are based on 225% excess in the permafrost and 45% excess below the permafrost. Top of tail slurry is designed to be 493' below base of permafrost.) Lead Slurrv (minimum pump time 206 min.) ArcticSet III Lite @ 10.7 ppg, - 4.45 ft3fsk 3 0.7632 ft 1ft x (108') x 1.00 (no excess) = 3 0.3132 ft 1ft x (1399' -108') x 3.25 (225% excess) = 0.3132 ft3fft x (1892' -1399') x 1.45 (45% excess) = 82.4ft3 + 1314.1 ft3+ 223.9ft3 = 1620.4 ft3 f 4.45 ft3fsk = Round up to 365 sks 82.4 ft3 1314.1ft3 223.9 ft3 1620.4 ft3 364.1 sks Have 230 sks of additional Lead on location for Top Out stage, if necessary. Tail Slurrv (minimum pump time 165 min.) LiteCRETE @ 12.0 ppg - 2.47 ft3fsk 0.3132 ft3fft x (3292' - 1892') x 1.45 (45% excess) = 0.4257 ft3fft x 80' JShoe Joint) = 635.8 ft3 + 34.1 ft = 669.9 ft31 2.47 ft3fsk = Round up to 272 sks 635.8 ft3 34.1 ft3 669.9 ft3 271.2 sks BHST = 5rF, Estimated BHCT = 74°F. (BHST calculated using a gradient of 2SFf100 ft. below the permafrost) PUMP SCHEDULE Stage Pump Rate (bpm) Stage Volume Cumulative Stage Time Time (min) (bbl) (min) CW100 5 10 2.0 2.0 Pressure test lines 10.0 12.0 CW100 5 30 6.0 18.0 Drop Bottom Plug 4.0 22.0 MudPUSH II 6 40 6.7 28.7 Lead Slurry 7 289 41.3 70.0 Tail Slurry 5 120 24.0 94.0 Drop top plug 4.0 98.0 Water spacer 5 20 4.0 102.0 XO to Rig 4.0 106.0 Displacement 7 224 32.0 138.0 Bump Plug 3 20 6.7 144.7 MUD REMOVAL Recommended Mud Properties: 9.6 ppg, As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 10.5 ppg MudPUSH* II, Pv? 17-20, Ty ? 20-25 Centralizers: Recommend 2 per joint on Shoe track, 1 per joint to top of tail cement ORIGINAL. Rig: Doyon 141 Location: Kuparuk (Meltwater) Client: ConocoPhillips Alaska, Inc. Revision Date: 1/12/2004 Prepared by: Mike Martin Location: Anchorage, AK Phone: (907) 265-6205 Mobile: (907) 229-6266 email: martin13@slb.com Previous Csg. < 95/8",40.0#, L-80 grade STC, AS Modified at 3,292 ft. MD < 7",26.0#, L-80 grade STC, AS Modified in 8 1/2" OH < Top ofTail at 9,162 ft. MD < X-over at 9,462 ft. MD < TopofCaim Fm. at 9,662 ft. MD < 4 1/2", 12.6#, L-80 grade in 8 1/2" OH TD at 10,849 ft. MD (5,612 ft. TVD) Mark of Schlumberger Preliminary Job Design based on limited input data. For estimate purposes only. Icb bll p Volume Calculations and Cement Systems Volumes are based on 75% excess. Top of tail slurry is designed to be5300' above top of Cairn formation. Tail Slurry (minimum thickening time 198 min.) GasBLOK wI Class G + 0600G, 0047, 0065, and B155 per lab testing 3 @ 15.8 ppg, 1.17 ft Isk 0.1268ft3/ft x 300' x 1.75 (75% excess) = 0.2836 ft31ft x (10849' - 9462') x 1.75 (75% excess) = 0.0854 ft3/ft x 120' (Shoe Joint) = 66.6 ft3 + 688.4 ft3 + 10.2 ft3 = 765.2 ft3/1.17 ft3/sk = Round up to 654 sks 66.6 ft3 688.4 ft3 10.2 ft3 765.2 ft3 654 sks BHST = 139°F, Estimated BHCT = 110°F. (BHST calculated using a gradient of 2.5°F/100 ft. below the permafrost) PUMP SCHEDULE Stage Pump Rate (bpm) Stage Volume Cumulative Stage Time Time (min) (bbl) (min) CW100 5 10 2.0 2.0 10.0 12.0 CW100 5 50 10.0 22.0 MudPUSH II 5 30 6.0 28.0 GasBLOK Slurry 5 136 27.2 55.2 Drop Plug 5.0 60.2 Displacement 5 355 71.0 131.2 Slow rate 3 20 6.7 137.9 Bump Plug 1.5 7.8 5.2 143.1 MUD REMOVAL Recommended Mud Properties: 10 ppg, Pv < 15, Ty < 15. As thin and light as possible to aid in mud removal during cementing. Spacer Properties: 11.0 ppg MudPUSH* II, Pv? 19-22, Ty? 22-29 Centralizers: Recommend 1-W per joint on the 5-W' and 3-W casing strings throughout cemented interval. ORIGINAL Meltwater 2P-419 I'ector Proposed Completion Schematic 4-1/2" Completion String 30" x 16" 62.6# @ +1- 108' MD (Insulated) Depths are based on Doyon 141 RKB Surface csg. 95/8" 40.0# L-80 BTC +1- 3292' MD I 2355' TVD 7" 26# L-80 STCM x 4 %" 12.6# L-80 1ST Mod crossover at +1- 9462' MD I 5023' TVD Future Perforations Production csg 7" 26# L-80 STCM x 4 %" 12.6# L-80 IBT Mod +1- 10849' MD /5612' TVD G· YPh-II- . dnOCO·, I ~pS 4 %" FMC Gen 5 Tubing Hanger, 4 %" L-80 1ST Mod pin down 4 %" 12.6# L-80 1ST Mod Spaceout Pups as Required 4 %" 12.6# L-80 1ST Mod Tubing to Surface 4 %" Cameo 'DB' nipple wI 3.875" No-Go Profile. 4 %" x 6' L-80 handling pups installed above and below, 1ST Mod, set at +1- 500' MD 4 %" 12.6# L-80 1ST Mod tubing to landing nipple 4 %" x 1" Cameo 'KBG-2' mandrel wI shear valve, pinned for 3000 psi shear (casing to tubing differential), 4 %" x 6' L-80 handling pups installed above and below, 1ST Mod 4 %" Saker 'CMU' sliding sleeve wI 3.813" Cameo DS profile, 1ST Mod box x pin. 4 %" x 6' L-80 1ST Mod handling pup installed above 4 %" Cameo 'DB' nipple wI 3.75" No-Go profile. 4 %" x 12' L-80 1ST Mod spacaeout pup installed above, 4 %" x 6' handling pup installed below 4 %" Baker 80-40 GBH-22 casing seal assembly wI 15' stroke, 4 %" L-80 1ST Mod box up, 4 %" x 6' L-80 1ST Mod handling pup installed on top Saker Seal Sore Extension, 7" STCM x 4 %" 1ST Mod SSE set at +1- 200' MD above the top of the Sermuda interval (or 200' MD above the Cairn if present) ORIGINAL 1/12/2004 N 2P-438 9.6 ppg shallow zone 1 ppg shallow zone 2 P-419 Proposed SFD 1/15/2004 ~.... CHASE Chase Manhaltan Bank USA, N.A. Valid Up TO. 5000 Dollars . . 200 White Clay Center Dr., Newark, DE 19711 .. ... ... .. . .. ........... "... . / - /' , . .// / . f<... "'~ .,~l4 ¡/~<æTÊ" ...... 1 : 0 ~ ¡. ¡. 0 0 ¡. I. 1.1: 2 ¡. B I. 7 ¡. 11 0 7 11 2 7 b II- ¡. 0 ¡. 7 -- DOLLARS 6J PAY TO THE .5 .("-,q T 6 or L1 L IIS(( â 14 cr7 Cc· .... ORDER OF n ... r[ - __---- (;24:. )¿¿1/~~Jvê c/ cjv/ß~s "_,,,!i;H<7!t().() $ 1(:0. 00 DATE t31c?v(vClV\,! 2Gc¿r-<~/311 SHARON K. ALLSUP-DRAKE CONOCOPHILLlPS 3760 PERENOSA ANCHORAGE AK 99515 1017 . . . . TRANSMJT AL LETTER CHECKLIST CIRCLE APPROPRJA TE LETTERIP ARA GRAPH S TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME <í<?/~Zß c//l PTD# ;20 (/- () /./ s<t.(\J\.c.k ~~\\ CHECK WBA T ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI The permit is for a new wellbore segment of LATERAL existing well . Permit No, API No. . (If API num ber Production should continue to be reported as last two (2) digits a function of the original API number. stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(1), all (PH) records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API Dumber (50 - 70/80) from records, data and logs acquired for well (name on permit). SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Company Name) assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sampJe intervals through target zones. . Rev: 07/1 0/02 C\jody\templates Field & Pool KUPARUK RIVER, MELTWATER OIL - 490140 Well Name: KUPARUK RIV U MELT 2P-419 Program SER Well bore seg 0 PTD#: 2040170 Company CONOCOPHILLlPS ALASKA INC Initial ClasslType SER I PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal 0 Administration 1 P~rmit fee attached _ _ _ _ . _ . . Yes _ _ _ _ . _ . . _ _ _ . . _ _ _ _ _ _ _ _ _ . _ _... _ _ _ _ _ _ _ _ 2 _Leas~number _appropri¡¡te . . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . _Y~s _ . _ _ _ _ _ _ .. _ _ _ _ _ _ . _ _ _ _ . _ _ . _ _ _ _ _ _ _ _ . . . _ . _ _ _ _ _ _ . . _ _ _ _ _ . _ 3 _U_nique weltnam~_a[1d (lI.!.mb_er . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Y~s . . . . . . . RepJa.ce& propo$ed. i[1jectorXRU. 2P.-442 -t20.3~204). Jtle Z~-419. welU~ beioQ. dJilledJrom.é!. &lotfu.rt!1er. . . . . . . 4 Well Joc¡¡t~d ina d_efioe.d .pool_ _ _ . _ _ . . .. _ _ _ _ _ . . Yes _ . east t!1al1 that proposed for 2P~443 to _ayoid drilling to a sh_alJow" tligh pressure_zooe.. _ _ _ _ _ _ . _ . _ . _ _ _ _ _ . 5 WeJUoc¡¡t~d pr.oper .distance from drilling unitb.ound_ary. . _ _ _ _ . . . . . _ _ _ _ _ . _Yes _ _ . _ _ _ . . .. _ _ _ _ . . . _ _ _ _ _ . . . _ _ _ _ _ . .. _ _ _ _ _ . . . . . _ _ _ _ . _ _ _ . . . 6 WeIUoc¡¡t~d proper _dista[1ce. from otber wel]s. . . _ _ _ _ _ _ _ . . _ . . . _ _ _ _ _ _. .. _ _ _ _ .Y~s . . _ _ _ _ _ _ . . . . _ _ _ _ _' _ _ _ _ _ _ _ . . . _ _ _ _ _ _ . . . . _ _ _ _ _ _ 7 .S.ulf¡cientacreaQ.e.ayail¡¡blein drilJiogunjt _ _ _ _... _. _ _.. _ _ _ _ _. _.. . Yes CO 456A&pecifie_s.10-_acre.spacing. _ _ _.... _.. _. _ _ _ _ _.. _.. _ . _ _ _.. __ 8 Jf.d~viated, js weJlbore platincJuded _ _ . . . . . _ _ _ _ _ . . . _ . _ _ _ _ _ . . . Y~s _ _ _ _ . . . _ _ . . . . _ _ _ . . . .. _ _ _ _ . . . . _ _ _ _ _ . .. _ _ _ _ _ . . . . _ . _ . _ _ _ _ . . . _ _ _ _ _ _ . . . 9 .Operator OI1I}! affected party _ _ _ _ _ . . . . _ _ _ _ . . . . _ _ Y~s _ _ _ . _ . . . _ _ _ _ . . . . _ _ _ _ . . . . _ _ _ _ _ . . . _ _ _ . _ . _ . . _ _ _ _ . _ . . . _ 10 .Operator tlas.appropriate.Qo[1d inJorce . . . . . . . . . . . . . . _ . . . . . . . . . . . . . . . . . . .Y_es. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . _ . . . . . . . . . . . . . . . . . . . . _ . . . . . . . . . . . . . . . . . . 11 Permit can be issued without conservation order _ . . . . . . . . _ _ Y~s _ . . . . . _ . . . . . _ _ . . . . _ _ . _ . . . . . _ _ _ _ _ . . . Appr Date 12 P~rmit c.ao be issu.ed witbout administratil¡e.approvaJ _ _ _ _ . . . . _ _ _ _ _ . . . _ Yes. . _ _ _ . . . . . . _ _ _ . . . . . . . _ _ _ _ _ . . . . . _ _ _ . . . . _ _ _ _ _ . . . . . . SFD 1/15/2004 13 Can permit be approved before 15-daywait Yes 14 WelUocated within area al1d.strata .authorized by.lojectioo Ord~r # (puUO# incomm.eots) (For .Y~s . . . _ _ _ _ AIO.2.1. _ _ _ . . . . . _ _ _ _ . . . . _ _ _ _ _ _ _ . . . . . . . . . . _ 15 .All welJs.wit!1iJ1.114.mile.area.of reyiew id~otified (For &ervjc.e.w.e[l OOI}!). . . . . . . . . . . . . . . .Y~s . . . . . . . Non.e. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ............................... 16 Pre-produ.ced i[1jector; dur¡¡tion.of pre-production less_ ttlal13 months. (For.servtce well onJy) . . No. . _ _ _ _ _ _ . . . . . _ _ _ . . . . . _ _ _ _ _ . . . _ _ _ _ _ . . . . . . _ _ _ _ _ . . . . _ . . . . . . _ 17 ACMPF.il1ding.ofCon.si.ste[1cyhasbee.nj&suedfor.thispr:oject _ _ _ _.... _ _ _ _..... .NA . WelJdrilled from exjstiogpa.d. _..... _ _ _.... _. _ _... _ _ _ _ _ _... Engineering 18 .C.ooductor stril1g.provided _ _ . _ . . . . _ _ _ . . . . . _. _ _ _ _ . . . _ _ _ _ . . . . . Y~s _ _ . . . . _ _ . . . _ . . . _ _ . . . . _ . . . . . . _ _ _ . . . . . _ _ _ _ _ . . . . _ 19 .S.urfaœcasing. protects allknown. USQWs _ _ . . . . _ _ _ _ . . . . _ _ _ _ . .. _ _ NA . All aq.uifers ex~mpted by 4Q C¡:R 10.2(b)(31. SFD _ _ . . . . . _ _ _ . . . . .. _ _ _ . . . . 20 _CMTv.oladequate.to circ.ulate.o.n.cond_uctor& surf.c.sg _ _ _ _ _ . Yes. . _ _ _ _ . .. _ _ _ _ _ _ . . . . . _ _ . . . _ . . . . . _ _ _ _ . . . . . . _ _ _ _ _ . . . . . 21 .CMT vol adequate.to tie-in Jong .stri[1g to surf csg. . . _ _ _ . . . No _ _ _ Ann_ular di&p_osal my.be proposed.. . . . . . . _ _ _ . . . . . . _ _ . . . . . 22CMTwill coyeraJl knowJ1-Pfo.ductiye horizon.s. _ _ _ _ _ _ . _ . . . _ _ . . .Y~s _ _ _ _ _ . . . . . _ _. .... _ _ . . . . . _ _ _ _ _ _ . . . . _ _ _ _ _ _ . . . . . . 123 .C.asi[1g desig[1s ad.equa.te for C,T, B.&_permafrost _ . . . . _. _ _ _ . . . . . . . _ _ _ . . . . _ Y~s _ . _ _ . . . _ _ _ . . . . . _ _ _ _ . . .. _ _ _ _ _ . . . . . . _ _ _ . _ . . 24 _Adequ.ate.tankage_or re_serve pit. _ _ _ _ _ . . .' . _ _ _ . . . . _ _ _ _ . . . . _ _ _ _ . . No _ _ _ _ . . . Rig jsequippe.dwittl .steelpits.. No rese_lV'epjtpla[1oed. Wa.ste.to an approyed an.nulu& ordispos.al well.. _ _ _ _ . . 25 Jf.aJe-driIL tlas.a. 10-403 for .abandOl1meJ1t be~o approved _ _ . . . . _ _ _ . . . . _ _ _NA . . . _ _ _ . . . . . . _ _ _ _ . . . . . . _ _ _ _ . . . . . _ _ _ _ . . . . . . . _ _ _ _ _ _ _ _ . . . _ 26 Adequ.ate:'^Ie[lbore&epar¡¡tjo.npropo&ed................................. .Y~s. . . . . . . Pro~imit}!an.alysis pertorme.d. Cjose apprQaçhe.sjdentjfi~d.. TraveJiOQ.Gylil1der: plot jn.cluded, . . . . . _ . . . . . . _ 27 Jf.djverter required, dQes jtmeet reguJé!.tions . . . . . . _ _ . . . . .. _ _ _ . . . . _ _ Y~s _ . . . . . . _ _ . . . . . . _ _ _ _ . . . . . . _ _ _ _ . . . . . . . _ _ _ . . . . . _ _ _ _ . . . . . Appr Date 28 .DrilliogfJujd.programsGhematicß~eq.uipJistadequate... _ _..... _ _ Y~s _ _ _ExpectedBHPtn.B~(mu.da5.1to7.2EMW._PlannedMW9.6.ßisk.ofsballower!1i.gherpressureidel1tified, . TEM 1/15/2004 29 BOPEs,.d.o.they meetreguJé!.tion _ . _ _ _ _ _ . . . . . . . _ _ . . . . _ _ _ _ . . . Y~s _ _ _ . . . . . _ _ _ _ . . . . _ _ _ _ _ _ . . _ _ _ . . . . _ _ _ _ _ . . . . _ _ _ _ _ . . . . 'JR.'rIN\ 30 .B.OPEpress ratiog appropriate;.test to.(pu_t psig tn.comments) . _ . . . . _ _ . . . . . _ _ Y_es . . _ _ Masp.CaJcul.ated for Bermuda 1493psi. 35QO_p.si.appr.oprjate.CP_Al U&u¡¡lJy.tests to.50QO.psL _ _ _ . . . . 31Chokemanjfold compJies w/APt ßP-53 (May 64). . . . _ _ _ _ . . . . . . . . _ _ _ . . . . . _ _ . _ Yes. . . . _ _ _ . . . . _ _ _ . . . . . _ _ _ _ _ _ . . . . . _ _ _ _ . . . . . . . . . . . . _ . _ _ _ _ _ _ 32 Work will oCC.ur withoutoperatjoJ1.stlutdowJ1. . . . . . _ _ _ _ _ _ . .. _ _ _ _ . .Y~s . _ _ _ . . . . _ . . . . . _ _ _ _ _ _ _ . . . . . _ _ _ . . . . . . _ _ _ _ . . . . . _ _ _ _ _ _ . . . . . . _ _ _ _ . . 33 Is presence. Qf H2S gas. prOQable _ _ _ _ _ . .. _ _ _ _ _ _ _ _ . . . . . . _ _ _ . . . . _ _ _ _ . . . No. _ _ _ . . . . . _ _ _ _ . . . . . _ _ _ . _ _ _ . . . . . . . _ . _ _ . . . . . _ _ _ _ _ _ . . . 34 Meçhanicalcoodjt[o[1otwellswithinAOßYerified(for.servjcew~lJonJy).. _ _ _ _ NA... _ _ _ _Nowellswjtbio1/4mile¡¡ttopof.B.ermu_da.. _ _... _. _....... _ _ _ _....._ . . Date 1/15/2004 35 P~rmit c.a[1 be i.ssued w/o hydr:ogen. s.ulfide meaS.ures _ _ _ _ _ _ . . . . . . _ _ _ . _ . . . . _ _ _ . .Y~s _ 36 Data.preseoted on_ pote.ntial overpressure .zones _ _ _ _ . . . . . _ . . _ _ . _ . . _ . _ _ _ _ . . _ Y~s _ 37 .S~i.smicaJ1alysjs.ofsbaJlowgas_zooes.. _ _ _ . . . .. _ _ _ _ _ . . . . . . _. _.... _ . _ _ NA . . 38 _S~abedcondjtioo survey.(if off-shore) . . . _ . _ . . . . . _ . . _ _ _ _ _ . . . . . _ _ _ . . . . . _NA 39 _ CQnta.ct namelphol1eJor.weekly progre&s.reports [exploratory .0[1ly] _ _ _ _ . . .' .. _ . . . . _NA _ _ _ . . . . , - - - - ~ - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - - - - - - -- Geology Appr SFD . Res~rvoir expected to be under pre&sur:ed (5..1-, 7..2 ppg.EMW)~ wiJI be dr:illed wi.th 9.6 ppg. mud, , . _ _ _ . . . , . . _ . Shallow pressure.h.as beeJ1e[1co.u[1tered jn_ weJls drilled from the wester[] .slotso[1th.e.p¡¡d., _ , _ CPAI.moyed the surtace 10c.a[1d the shallow portjo_n.of thi.s .w.ell to.tbe ea.st to .avojd. this pressure. SFD _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - Geologic Commissioner: Date: Engineering Commissioner: Date , , Public C,I Commissioner í~6 , / / Date Dr5 1/10/1- e e Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding infonnation, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of infonnation. **** REEL HEADER **** LDWG 04/04/06 AWS 01 **** TAPE HEADER **** LDWG 04/04/06 01 *** LIS COMMENT RECORD *** C:<o )C- {) / '1 bó/J / L 0SC¡ RECE\VED 2. '\ 2004 _\or! A!øa0\\ &=com I I. . , .. !!!!!!!!!! ! ! ! ! !!!!! LDWG File Version 1.000 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! Extract File: LISTAPE.HED TAPE HEADER MELTWATER UNIT MWD /MAD LOGS # WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: # JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: MWD RUN 1 1 S. TUFT ON D. GLADDEN # SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: FEL: FWL: ELEVATION(FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: GROUND LEVEL: # WELL CASING RECORD 1ST STRING 2ND STRING 3RD STRING PRODUCTION STRING # REMARKS: OPEN HOLE BIT SIZE (IN) 12.250 8.500 6.125 2P-419 501032048300 ConocoPhillips Alaska, Inc. BAKER HUGHES INTEQ 06-APR-04 MWD RUN 2 2 S. DRAKE M. THORTON 17 8N 7E 252.00 224.00 CASING SIZE (IN) 16.000 9.625 7.000 MWD RUN 3 3 LABRECQUE F. HERBERT DRILLERS DEPTH (FT) 108.0 3287.0 10065.0 10945.0 PER CONOCOPHILLIPS ALASKA STANDING ORDER, THE GAMMA RAY CURVE FROM THIS LOG IS THE DEPTH REFERENCE FOR THIS WELL. AS SUCH, NO DEPTH SHIFTS HAVE BEEN APPLIED. INDIVIDUAL MWD RUN DATA WAS MERGED IN THE FIELD PRIOR TO DELIVERY FROM THE WELL SITE. SURFACE LOCATION: LAT: N 70 DEG 03' 9.792" LONG: W150 DEG 26' 50.215" LOG MEASURED FROM D.F. AT 252.0 FT. ABOVE PERM. DATUM (M.S.L.) . COMMENTS: (I) Baker Hughes INTEQ run 1 utilized a Multiple Propagation Resistivity (MPR) and Gamma Ray with Near Bit Inclination services from 108 - 3292 feet MD (108 - 2354 TVD). (2) Baker Hughes INTEQ run 2 utilized the Advantage Porosity Logging Service (APLS) which includes the Optimized Rotational Density (ORD), Caliper Corrected Neutron (CCN), along with Drill Collar Pressure (DCP) and MPR Resistivity services from 3292 - 10074 feet MD (2354 - 5281 TVD). (3) Baker Hughes INTEQ run 3 utilized the Slim Advantage Porosity Logging Service (APLS) which includes the Optimized Rotational Density (ORD), Caliper Corrected Neutron (CCN), along with an Annular Pressure (AP) tool and MPR Resistivity services from 10074 - 10945 feet MD (5281 - 5670 TVD). (4) Per ConocoPhi11ips Alaska instructions, the Gamma Ray curve from this log is the depth reference for this well. As such, no depth shifts have been applied. REMARKS: (I) Depth of 9 5/8" casing Shoe - Logger: 3287 feet MD (2351 TVD) Depth of 9 5/8" Casing Shoe - Driller: 3287 feet MD (2351 TVD) (2) The interval from 3245 to 3292 feet MD (2334 - 2354 TVD) was not logged due to the presence of the 9 5/8" casing. (3) The interval from 10027 to 10074 feet MD (5260 - 5281 TVD) was not logged due to the presence of the 7" casing. (4) Depth of 7" Casing Shoe - Logger: 10065 feet MD (5277 TVD) Depth of 7" Casing Shoe - Driller: 10065 feet MD (5277 TVD) (5) The interval from 10901 to 10945 feet MD (5620 - 5670 TVD) was not logged due to sensor-bit offset at TD. $ Tape Subfile: 1 91 records... Minimum record length: Maximum record length: 8 bytes 132 bytes **** FILE HEADER **** LDWG .001 1024 *** LIS COMMENT RECORD *** !!!!!!! ! ! !!! !!!!! !! LDWG File Version 1.000 !!! ! ! ! ! !!!!!!!!!! !! Extract File: FILE001.HED FILE HEADER FILE NUMBER: EDITED MERGED MWD Depth shifted DEPTH INCREMENT: # FILE SUMMARY PBU TOOL CODE MWD $ 1 and clipped curves; all bit runs merged. .5000 START DEPTH 108.0 STOP DEPTH 10945.0 # BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH $ # MERGED DATA SOURCE PBU TOOL CODE MWD MWD MWD $ BIT RUN NO 1 2 3 MERGE TOP 108.0 3245.0 10027.0 MERGE BASE 3245.0 10027.0 10945.0 # REMARKS: MERGED PASS. NO DEPTH SHIFTS WERE APPLIED AS THIS LOG IS THE DEPTH REFERENCE FOR THIS WELL. $ # *** INFORMATION TABLE: CONS MNEM VALU ------------------------------ WDFN LCC CN WN FN COUN STAT 2p-419_5.xtf 150 ConocoPhillips Alaska 2P-419 Meltwater Unit North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GR GR GRAM 0.0 RPD RPD RPD 0.0 RPM RPM RPM 0.0 RPS RPS RPS 0.0 RPX RPX RPX 0.0 RHOB RHOB BDCM 0.0 DRHO DRHO DRHM 0.0 PEF PEF DPEM 0.0 NPHI NPHI NPCKSM 0.0 ROP ROP ROPS 0.0 FET FET RPTH 0.0 MTEM MTEM TCDM 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 52 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.500000 Frame spacing units: [F ] Number of frames per record is: 19 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.500 * F ONE DEPTH PER FRAME Tape depth ID: F 12 Curves: Name Tool Code Samples Units Size Length 1 GR MWD 68 1 GAP I 4 4 2 RPD MWD 68 1 OHMM 4 4 3 RPM MWD 68 1 OHMM 4 4 4 RPS MWD 68 1 OHMM 4 4 5 RPX MWD 68 1 OHMM 4 4 6 RHOB MWD 68 1 G/C3 4 4 7 DRHO MWD 68 1 G/C3 4 4 8 PEF MWD 68 1 BN/E 4 4 9 NPHI MWD 68 1 PU-S 4 4 10 ROP MWD 68 1 FPHR 4 4 11 FET MWD 68 1 HR 4 4 12 MTEM MWD 68 1 DEGF 4 4 ------- 48 Total Data Records: 1141 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 108.000000 10945.000000 0.500000 feet **** FILE TRAILER **** Tape Subfile: 2 1190 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** FILE HEADER **** LDWG .002 1024 *** LIS COMMENT RECORD *** !!!!!!!!!!!!!!!!!!! LDWG File Version 1.000 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! Extract File: FILEOll.HED FILE HEADER FILE NUMBER: 2 RAW MWD header data for each bit run in separate files. 1 .2500 Curves and log BIT RUN NO: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE MWD $ START DEPTH 100.0 STOP DEPTH 3245.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG) MINIMUM ANGLE: MAXIMUM ANGLE: # TOOL STRING (TOP TO VENDOR TOOL CODE DIR MPR GRAM $ BOTTOM) TOOL TYPE DIRECTIONAL MULT. PROP. GAMMA RAY RESIST. # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TEMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): # 23-JAN-04 MSB 18655 8.25 MPR MEMORY 3292.0 100.0 3245.0 o .0 65.1 TOOL NUMBER DHA 7113 MPR 8028 SRIG 58017 12.250 108.0 Spud 9.55 .0 .0 225 .0 .000 .000 .000 .000 102.0 .0 .0 .0 .00 .000 .0 o BIT RUN 1 (MWD Run 1). GR/MPR. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWD-API) RPCL - DEEP PHASE RESISTIVITY (OHMM) RPSL - MEDIUM PHASE RESISTIVITY (OHMM) RPCH - SHALLOW PHASE RESISTIVITY (OHMM) RPSH - EXTRA SHALLOW PHASE RESISTIVITY (OHMM) ROPS - RATE OF PENETRATION (FPHR) RPTH - FORMATION EXPOSURE TIME (MIN) TCDM - TEMPERATURE (DEGF) PER CONOCOPHILLIPS ALASKA (WAYNE CAMPAIGN), THE REMARKS: FOLLOWING CURVES ARE NOT PRESENTED ON THE MPR RESISTIVITY LOG BUT ARE PRESENTED HERE FOR THE SAKE OF COMPLETENESS: RACL - DEEP ATTENUATION RESISTIVITY (OHMM) RASL - MEDIUM ATTENUATION RESISTIVITY (OHMM) RACH - SHALLOW ATTENUATION RESISTIVITY (OHMM) RASH - EXTRA SHALLOW ATTENUATION RESISTIVITY (OHMM) $ # *** INFORMATION TABLE: CONS MNEM VALU ------------------------------ WDFN LCC CN WN FN COUN STAT 2p-419.xtf 150 ConocoPhillips Alaska 2P-419 Meltwater Unit North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GRAM GRAM GRAM 0.0 RPCL RPCL RPD 0.0 RPSL RPSL RPM 0.0 RPCH RPCH RPS 0.0 RPSH RPSH RPX 0.0 RACL RACL RAD 0.0 RASL RASL RACSLM 0.0 RACH RACH RAS 0.0 RASH RASH RACSHM 0.0 ROPS ROPS ROPS 0.0 RPTH RPTH RPTHM 0.0 TCDM TCDM TCDM 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 52 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.250000 Frame spacing units: [F ] Number of frames per record is: 19 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 12 Curves: Name Tool Code Samples Units Size Length 1 GRAM MWD 68 1 GAP I 4 4 2 RPCL MWD 68 1 OHMM 4 4 3 RPSL MWD 68 1 OHMM 4 4 4 RPCH MWD 68 1 OHMM 4 4 5 RPSH MWD 68 1 OHMM 4 4 6 RACL MWD 68 1 OHMM 4 4 7 RASL MWD 68 1 OHMM 4 4 8 RACH MWD 68 1 OHMM 4 4 9 RASH MWD 68 1 OHMM 4 4 10 ROPS MWD 68 1 FPHR 4 4 11 RPTH MWD 68 1 MINS 4 4 12 TCDM MWD 68 1 DEGF 4 4 ------- 48 Total Data Records: 663 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 100.000000 3245.000000 0.250000 feet **** FILE TRAILER **** Tape Subfile: 3 762 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** FILE HEADER **** LDWG .003 1024 *** LIS COMMENT RECORD *** !! ! !!!!!!! ! ! ! !!!! !! LDWG File Version 1.000 !!!!!!!!!! ! ! ! ! ! ! ! !! Extract File: FILE012.HED FILE HEADER FILE NUMBER: RAW MWD Curves and BIT RUN NO: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE MWD $ 3 log header data for each bit run in separate files. 2 .2500 START DEPTH 3245.0 STOP DEPTH 10027.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG) MINIMUM ANGLE: MAXIMUM ANGLE: # 31-JAN-04 MSB 18655 6.75 TC MEMORY 10074.0 3245.0 10027.0 o 63.8 66.2 TOOL STRING (TOP TO VENDOR TOOL CODE DIR CCN ORD MPR GRAM $ # BOTTOM) TOOL TYPE DIRECTIONAL CAL. COR. NEUTRON OPT. ROT. DENSITY MULT. PROP. RES IS. GAMMA RAY BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TEMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): # # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: # TOOL NUMBER DHA 90427 CCN 71630 ORD 51687 MPR 67280 SRIG 5078 8.500 3287.0 LSND 11.15 .0 .0 200 .0 .000 .000 .000 .000 131.0 .0 .0 .0 Sandstone .00 .000 .0 o BIT RUN 2 (MWD Run 2) . GR/MPR/oRD/CCN. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWD-API) RPCL - DEEP PHASE RESISTIVITY (OHMM) RPSL - MEDIUM PHASE RESISTIVITY (OHMM) RPCH - SHALLOW PHASE RESISTIVITY (OHMM) RPSH - EXTRA SHALLOW PHASE RESISTIVITY (OHMM) BDCM - BULK DENSITY COMPENSATED (G/CC) DRHM - DENSITY CORRECTION (G/CC) DPEM - PHOTOELECTRIC CROSS SECTION (B/E) NPCK - NEUTRON POROSITY, CALIPER & SALINITY CORRECTED (SANDSTONE PU) ROPS - RATE OF PENETRATION (FPHR) RPTH - FORMATION EXPOSURE TIME (MIN) TCDM - TEMPERATURE (DEGF) PER CONOCOPHILLIPS ALASKA (WAYNE CAMPAIGN), THE FOLLOWING CURVES ARE NOT PRESENTED ON THE MPR RESISTIVITY LOG BUT ARE PRESENTED HERE FOR THE SAKE OF COMPLETENESS: RACL - DEEP ATTENUATION RESISTIVITY (OHMM) RASL - MEDIUM ATTENUATION RESISTIVITY (OHMM) RACH - SHALLOW ATTENUATION RESISTIVITY (OHMM) RASH - EXTRA SHALLOW ATTENUATION RESISTIVITY (OHMM) $ *** INFORMATION TABLE: CONS MNEM VALU WDFN 2p-419.xtf ------------------------------ LCC CN WN FN COUN STAT 150 ConocoPhillips Alaska 2P-419 Meltwater Unit North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GRAM GRAM GRAM 0.0 RPCL RPCL RPD 0.0 RPSL RPSL RPM 0.0 RPCH RPCH RPS 0.0 RPSH RPSH RPX 0.0 RACL RACL RAD 0.0 RASL RASL RACSLM 0.0 RACH RACH RAS 0.0 RASH RASH RACSHM 0.0 BDCM BDCM BDCM 0.0 DRHM DRHM DRHM 0.0 DPEM DPEM DPEM 0.0 NPCK NPCK NPCKSM 0.0 ROPS ROPS ROPS 0.0 RPTH RPTH RPTHM 0.0 TCDM TCDM TCDM 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 68 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.250000 Frame spacing units: [F ] Number of frames per record is: 14 One depth per frame (value= 0) Datum Specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 16 Curves: Name Tool Code Samples Units Size Length 1 GRAM MWD 68 1 GAP I 4 4 2 RPCL MWD 68 1 OHMM 4 4 3 RPSL MWD 68 1 OHMM 4 4 4 RPCH MWD 68 1 OHMM 4 4 5 RPSH MWD 68 1 OHMM 4 4 6 RACL MWD 68 1 OHMM 4 4 7 RASL MWD 68 1 OHMM 4 4 8 RACH MWD 68 1 Om-1M 4 4 9 RASH MWD 68 1 OHMM 4 4 10 BDCM MWD 68 1 G/C3 4 4 11 DRHM MWD 68 1 G/C3 4 4 12 DPEM MWD 68 1 BN/E 4 4 13 NPCK MWD 68 1 PU-S 4 4 14 ROPS MWD 68 1 FPHR 4 4 15 RPTH MWD 68 1 MINS 4 4 16 TCDM MWD 68 1 DEGF 4 4 ------- 64 Total Data Records: 1938 Tape File Start Depth Tape File End Depth Tape File Level Spacing Tape File Depth Units 3245.000000 10027.000000 0.250000 feet **** FILE TRAILER **** Tape Subfile: 4 2048 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** FILE HEADER **** LDWG .004 1024 *** LIS COMMENT RECORD *** !!!!!!!!!!!!!! ! !!!! LDWG File Version 1.000 ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! !! Extract File: FILE013.HED FILE HEADER FILE NUMBER: RAW MWD Curves and BIT RUN NO: DEPTH INCREMENT: # FILE SUMMARY VENDOR TOOL CODE MWD $ 4 log header data for each bit run in separate files. 3 .2500 START DEPTH 10027.0 STOP DEPTH 10945.0 # LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME) : TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG) MINIMUM ANGLE: MAXIMUM ANGLE: 05-FEB-04 MSB 18655 4.75 TC MEMORY 10945.0 10027.0 10945.0 o 61.1 65.5 # TOOL STRING (TOP TO VENDOR TOOL CODE DIR CCN ORD MPR GRAM $ BOTTOM) TOOL TYPE DIRECTIONAL CAL. COR. NEUTRON OPT. ROT. DENSITY MULT. PROP. RESIS. GAMMA RAY TOOL NUMBER SDS 4361 SDN 44706 SDN 44706 MPR 54694 SRIG 58019 # BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): 6.125 3287.0 # BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3): RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TEMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: LSND 10.20 .0 .0 300 .0 .000 .000 .000 .000 123.0 .0 .0 .0 # NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): Sandstone .00 .000 # TOOL STANDOFF (IN): EWR FREQUENCY (HZ): .0 o # REMARKS: BIT RUN 3 (MWD Run 3). GR/MPR/oRD/cCN. CURVE GLOSSARY: GRAM - GAMMA RAY APPARENT (MWD-API) RPCL - DEEP PHASE RESISTIVITY (OHMM) RPSL - MEDIUM PHASE RESISTIVITY (OHMM) RPCH - SHALLOW PHASE RESISTIVITY (OHMM) RPSH - EXTRA SHALLOW PHASE RESISTIVITY (OHMM) BDCM - BULK DENSITY COMPENSATED (G/CC) DRHM - DENSITY CORRECTION (G/CC) DPEM - PHOTOELECTRIC CROSS SECTION (B/E) NPCK - NEUTRON POROSITY, CALIPER & SALINITY CORRECTED (SANDSTONE PU) ROPS - RATE OF PENETRATION (FPHR) RPTH - FORMATION EXPOSURE TIME (MIN) TCDM - TEMPERATURE (DEGF) PER CONOCOPHILLIPS ALASKA (WAYNE CAMPAIGN), THE FOLLOWING CURVES ARE NOT PRESENTED ON THE MPR RESISTIVITY LOG BUT ARE PRESENTED HERE FOR THE SAKE OF COMPLETENESS: RACL - DEEP ATTENUATION RESISTIVITY (OHMM) RASL - MEDIUM ATTENUATION RESISTIVITY (OHMM) RACH - SHALLOW ATTENUATION RESISTIVITY (OHMM) RASH - EXTRA SHALLOW ATTENUATION RESISTIVITY (OHMM) $ # *** INFORMATION TABLE: CONS MNEM VALU ------------------------------ WDFN LCC CN WN FN COUN STAT 2p-419.xtf 150 ConocoPhillips Alaska 2P-419 Meltwater Unit North Slope Alaska *** INFORMATION TABLE: CIFO MNEM CHAN DIMT CNAM ODEP ---------------------------------------------------- GRAM GRAM GRAM 0.0 RPCL RPCL RPD 0.0 RPSL RPSL RPM 0.0 RPCH RPCH RPS 0.0 RPSH RPSH RPX 0.0 RACL RACL RAD 0.0 RASL RASL RACSLM 0.0 RACH RACH RAS 0.0 RASH RASH RACSHM 0.0 BDCM BDCM BDCM 0.0 DRHM DRHM DRHM 0.0 DPEM DPEM DPEM 0.0 NPCK NPCK NPCKSM 0.0 ROPS ROPS ROPS 0.0 RPTH RPTH RPTHM 0.0 TCDM TCDM TCDM 0.0 * FORMAT RECORD (TYPE# 64) Data record type is: 0 Datum Frame Size is: 68 bytes Logging direction is down (value= 255) Optical Log Depth Scale Units: Feet Frame spacing: 0.250000 Frame spacing units: [F ] Number of frames per record is: 14 One depth per frame (value= 0) Datum specification Block Sub-type is: 1 FRAME SPACE = 0.250 * F ONE DEPTH PER FRAME Tape depth ID: F 16 Curves: Name Tool Code Samples Units Size Length 1 GRAM MWD 68 1 GAP I 4 4 2 RPCL MWD 68 1 OHMM 4 4 3 RPSL MWD 68 1 OHMM 4 4 4 RPCH MWD 68 1 OHMM 4 4 5 RPSH MWD 68 1 OHMM 4 4 6 RACL MWD 68 1 OHMM 4 4 7 RASL MWD 68 1 OHMM 4 4 8 RACH MWD 68 1 OHMM 4 4 9 RASH MWD 68 1 OHMM 4 4 10 BDCM MWD 68 1 G/C3 4 4 11 DRHM MWD 68 1 G/C3 4 4 12 DPEM MWD 68 1 BN/E 4 4 13 NPCK MWD 68 1 PU-S 4 4 14 ROPS MWD 68 1 FPHR 4 4 15 RPTH MWD 68 1 MINS 4 4 16 TCDM MWD 68 1 DEGF 4 4 ------- 64 Total Data Records: 263 Tape File Start Depth 10027.000000 Tape File End Depth 10945.000000 · Tape File Level spacing Tape File Depth Units 0.250000 feet **** FILE TRAILER **** Tape Subfile: 5 373 records... Minimum record length: Maximum record length: 8 bytes 4124 bytes **** TAPE TRAILER **** LDWG 04/04/06 01 **** REEL TRAILER **** LDWG 04/04/06 AWS 01 Tape Subfile: 6 2 records... Minimum record length: Maximum record length: 132 bytes 132 bytes
